Edgar Filing: ENBRIDGE INC

Have a 'say on pay'

Vote on our approach to executive compensation.

While this vote is non-binding, it gives shareholders an opportunity to provide important input to our Board.

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 6-K

Report of Foreign Issuer
Pursuant to Rule 13a-16 or 15d-16 of
the Securities Exchange Act of 1934

Dated April 2, 2013
Commission file number 001-15254

ENBRIDGE INC.
(Exact name of Registrant as specified in its charter)


Canada (State or other jurisdiction of incorporation or organization)		None (I.R.S. Employer Identification No.)
3000, 425 - 1^st Street S.W. Calgary, Alberta, Canada T2P 3L8 (Address of principal executive offices and postal code)
(403) 231-3900 (Registrants telephone number, including area code)

Indicate by check mark whether the Registrant files or will file annual reports under cover of Form 20-F or Form 40-F.


Form 20-F		o		Form 40-F		ý

Indicate by check mark if the Registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):


Yes		o		No		ý

Indicate by check mark if the Registrant is submitting the Form 6-K in paper as permitted by regulation S-T Rule 101(b)(7):


Yes		o		No		ý

Indicate by check mark whether the Registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.


Yes		o		No		ý

If "Yes" is marked, indicate below the file number assigned to the Registrant in connection with Rule 12g3-2(b):

N/A

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE REGISTRATION STATEMENTS ON FORM S-8 (FILE NO. 333-145236, 333-127265, 333-13456, 333-97305 AND 333-6436), FORM F-3 (FILE NO. 333-185591 AND 33-77022) AND FORM F-10 (FILE NO. 333-181333) OF ENBRIDGE INC. AND TO BE PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

The following documents are being submitted herewith:

1.: Notice of Meeting and Management Information Circular;
2.: Form of Proxy; and
3.: Annual Report for the year ended December 31, 2012.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	ENBRIDGE INC. (Registrant)
Date: April 2, 2013
	By:	/s/ ALISON T. LOVE Alison T. Love Vice President & Corporate Secretary

Contents

Letter to shareholders			1
Notice of our 2013 annual meeting of shareholders			2
Management information circular			3
	1. About the meeting		4
	What the meeting will cover		4
	Who can vote		4
	How to vote		5
	Electing our directors		7
	Appointing our auditors		18
	Having a "Say on pay"		20
	Shareholder proposals		20
	2. Governance		21
	Our governance practices		21
	A culture of ethical conduct		21
	The role of the board		23
	Our expectations of our directors		25
	Board evaluation		27
	Board committees		28
	3. Compensation		36
	Directors		36
		Compensation discussion and analysis	36
		2012 results	38
	Executives		41
		Compensation discussion and analysis	41
		2012 results	70
	4. Loans to directors and senior officers		78
	5. Directors' and officers' liability insurance		78

March 5, 2013

Dear shareholder

It is our pleasure to invite you to attend the Enbridge Inc. annual meeting of shareholders on May 8, 2013 at the Metropolitan Conference Centre, Ballroom in Calgary.

This meeting is your opportunity to vote on the items of business, hear about our performance over the past year and learn more about our plans for making sure Enbridge Inc. remains one of your most valued investments.

You will also be able to meet the Board of Directors and senior management and talk to other Enbridge Inc. shareholders.

This document includes a formal notice of the meeting and the management information circular, which explains what the meeting will cover, the voting process, governance and other important information, such as how we make our compensation decisions and why. The package you received also includes either a brief summary about Enbridge Inc. or our full 2012 annual report, if you asked us to send it to you.

It's important to vote. Please take some time to review this document and then vote your common shares, either by proxy or by attending the meeting in person.

Sincerely,


David A. Arledge Chair, Board of Directors		Al Monaco President & Chief Executive Officer

1 ENBRIDGE INC.

Notice of our 2013 annual meeting of shareholders

You are invited to the Enbridge Inc. 2013 annual meeting of shareholders.

When

May 8, 2013
1:30 p.m. (mountain daylight time) (MDT)

Where

Metropolitan Conference Centre, Ballroom
333-4th Avenue S.W.
Calgary, Alberta (Canada)

Your vote is important

Please remember to vote your common shares. If you held Enbridge Inc. common shares at the close of business on March 14, 2013 you are entitled to receive notice of this meeting or any adjournment of it and vote your common shares.

The Board of Directors has approved the contents of this circular and has authorized us to send it to you. It has also given us approval to send it to our auditors.

By order of the Board,

Alison T. Love
Vice President & Corporate Secretary

Calgary, Alberta
March 5, 2013

2013 Management information circular 2

Management information circular

You have received this management information circular (circular) because you owned Enbridge common shares (Enbridge shares or common shares) at the close of business on March 14, 2013 (record date).

As a shareholder, you have the right to attend our annual meeting (meeting) of shareholders on May 8, 2013 and to vote your Enbridge shares. You can vote in person or by proxy, using the enclosed form.

ABOUT THIS DOCUMENT

This circular is furnished in connection with the solicitation of proxies by and on behalf of the management of Enbridge for use at the meeting and any adjournment of the meeting.

This circular explains what the meeting will cover, the voting process and other important information you need to know, such as:
•  the directors who have been nominated to our Board of Directors (Board or Board of Directors);
•  the auditors;
•  our governance practices; and
•  2012 compensation for our directors and officers.

In this document, you and your mean holders of Enbridge common shares.

We, us, our, company and Enbridge mean Enbridge Inc.

All dollar amounts are in Canadian dollars ($ or CA$) unless stated otherwise. US$ means United States of America (US) dollars.

VOTING

It's important to vote your Enbridge shares. To encourage you to vote, Enbridge employees may contact you in person or by phone. We pay for the cost of soliciting your vote and our employees do not receive a commission or any other form of compensation for it.

ACCESSING DOCUMENTS

You will find important disclosure and governance documents on our website (www.enbridge.com), including our quarterly and annual management's discussion and analysis (MD&A) and financial statements and notes, 2012 annual report, annual information form for the year ended December 31, 2012 and this circular. Copies are also available free of charge from our Corporate Secretary by phone, fax or email.

T. 1.403.231.3900
F. 1.403.231.5929
email: corporatesecretary@enbridge.com

You can also find these and other documents on SEDAR (www.sedar.com).

COMMUNICATING WITH THE BOARD

You can write to our Board or to individual directors by contacting our Corporate Secretary:

Alison T. Love, Vice President & Corporate Secretary
Enbridge Inc.
3000, 425 – 1st Street S.W.,
Calgary, Alberta, Canada T2P 3L8
email: corporatesecretary@enbridge.com

Our head office is also our principal executive and registered office.

This circular and proxy form will be mailed to shareholders on or close to April 2, 2013. Unless we state otherwise, information in this circular is as of March 5, 2013.

3 ENBRIDGE INC.

1. About the meeting

WHAT THE MEETING WILL COVER

There will be four items of business:

Financial statements(www.enbridge.com/InvestorRelations)

You will receive our 2012 consolidated financial statements and the auditors' report. You can download a copy of our 2012 annual report from our website (www.enbridge.com) if you did not receive a copy with this package.

Directors (see page 7)

You will elect directors to our Board of Directors for a term of one year. You can read about the nominated directors, including their backgrounds, experience and the committees of the Board (Board Committees or any one, a committee) they sit on, starting on page 8.

Live audio webcast

We are broadcasting a live audio webcast of our 2013 meeting if you're unable to attend in person.

Be sure to check our website closer to the meeting date for details.

We will also post a recording of the meeting on our website after we hold it.

Auditors (see page 18)

You will vote on reappointing the auditors. Representatives of PricewaterhouseCoopers LLP (PwC) will be at the meeting to answer any questions. You can read about the services they provided in 2012 and the fees we paid them starting on page 19.

Having a "say on pay" (advisory vote) (see page 20)

You may also vote on our approach to executive compensation. This is a non-binding advisory vote.

As of the date of this circular, the Board and management are not aware of any other items of business to be brought before the meeting.

We need a quorum

We need a quorum to hold the meeting and transact business. This means the people attending the meeting must hold or represent by proxy at least 25% of the total number of issued and outstanding common shares of Enbridge.

Sending of materials

We are not using what is referred to as "notice-and-access" to send this information circular and related materials to our shareholders for this meeting, nor are we sending these materials directly to non-objecting beneficial owners (NOBOs).

We are sending these materials directly to our registered shareholders and indirectly to all non-registered shareholders through their intermediaries. We will pay for an intermediary to deliver these materials and a voting instruction form to objecting beneficial owners (OBOs).

WHO CAN VOTE

Our authorized share capital consists of an unlimited number of Enbridge common shares and an unlimited number of non-voting preferred shares, issued in series. Only holders of common shares have full voting rights.

If you held common shares at the close of business on March 14, 2013 you are entitled to attend the meeting or any adjournment, and vote your common shares. Each Enbridge common share you hold represents one vote.

Principal owners of common shares

As of March 5, 2013, there are 809,283,814 common shares of Enbridge issued and outstanding. There are also 10 series of preference shares of Enbridge issued and outstanding, none of which will be voting at the meeting.

The Board and management are not aware of any shareholder who directly or indirectly owns or exercises or directs control over more than 10% of our common shares.

2013 Management information circular 4

HOW TO VOTE

You can attend the meeting and vote your common shares in person or you can vote by proxy.

Voting by proxy

Registered shareholders

You are a registered shareholder if you hold your common shares in your name (in such case, you have a share certificate).

Voting by proxy is the easiest way to vote. It means you are giving someone else the authority to attend the meeting and vote on your behalf (called your proxyholder).

Al Monaco (President & Chief Executive Officer) and David A. Arledge (Chair of the Board or Chair), have agreed to act as the Enbridge proxyholders. If you appoint the Enbridge proxyholders but do not indicate on the enclosed form how you want to vote your common shares, they will vote as the Board of Directors recommends:

•: for electing the nominated directors;
•: for re-appointing the auditors; and
•: for the advisory vote on our approach to executive compensation.

You can appoint someone else to be your proxyholder. This person does not need to be a shareholder. To do so, do not check the names of the Enbridge proxyholders on your proxy form. Instead, check the second box and print the name of the person you want to act on your behalf. Make sure the person you're appointing knows that you have appointed them as your proxyholder and that he or she needs to attend the meeting. Your proxyholder will need to register with our transfer agent when they arrive at the meeting.

Proxyholders must vote your common shares according to your instructions, including on any ballot that may be called. If there are changes to the items of business or new items properly come before the meeting, a proxyholder can vote as he or she sees fit.

About the registrar and transfer agent

The registrar and transfer agent for our shares is CIBC Mellon Trust Company (CIBC Mellon). Canadian Stock Transfer Company Inc. acts as the administrative agent for CIBC Mellon. To protect shareholder confidentiality, CIBC Mellon collects the votes and counts them for us.

Registered shareholders can vote by mail, phone, fax or online. Choose the method you prefer and then carefully follow the voting instructions on the enclosed form.

If you are voting by mail or fax, complete your proxy form, sign and date it, and then send it to Canadian Stock Transfer Company acting as administrative agent for CIBC Mellon:

Canadian Stock Transfer Company
P.O. Box 721
Agincourt, Ontario M1S 0A1
Fax: 1.866.781.3111 (toll-free in North America; outside of North America: 1.416.368.2502)

Canadian Stock Transfer Company must receive your instructions by 6 p.m. MDT on May 6, 2013 regardless of the voting method you choose. If the meeting is postponed or adjourned, your instructions must be received by 6 p.m. MDT two business days before the meeting is reconvened.

Proxy voting on the internet

If you are a registered shareholder, you can also appoint a proxyholder on the internet at www.proxypush.ca/enb (follow the onscreen instructions). Your proxyholder will need to register with our transfer agent at the meeting.

Hold common shares as both a registered and non-registered shareholder?

If some of your common shares are registered in your name and some are held by your nominee, you will need to follow two sets of voting instructions.

Please follow the instructions carefully. The voting process is different for registered and non-registered shareholders.

5 ENBRIDGE INC.

Non-registered shareholders

You are a non-registered (or beneficial) shareholder if your bank, trust company, securities broker, trustee or other financial institution (your nominee) holds your common shares for you in a nominee account. This means you do not have a physical share certificate but your common shares are recorded on the nominee's electronic system.

Only proxies deposited by registered shareholders can be recognized and acted upon at the meeting. If you are a beneficial shareholder, you will need to follow the voting instructions of your nominee.

Each nominee has its own voting instructions, but you can generally vote by mail, phone, fax or online. Carefully follow the instructions on the voting information form in the package sent to you by your nominee. Your nominee needs enough time to receive your instructions and then send them to our transfer agent, so it's important to complete the form right away.

Voting in person

Voting in person gives you the opportunity to meet face to face with management and interact with our Board.

Registered shareholders

If you are a registered shareholder and want to attend the meeting and vote in person, do not complete or return the enclosed proxy form. When you arrive at the meeting, please see a representative from CIBC Mellon to register.

Non-registered shareholders

If you are a beneficial shareholder and you want to attend the meeting and vote in person, your nominee needs to appoint you as proxyholder. We do not have a record of the number of common shares you own or how many votes they represent because your common shares are held in a nominee account and are not registered in your name. Print your name on the voting instruction form you received from your nominee and carefully follow the instructions provided. Do not indicate your voting instructions. Be sure to register with a representative from Broadridge Investor Communications Solutions when you arrive at the meeting.

All shareholders will be required to present photo identification to gain access to the meeting.

Changing your vote

If you vote by proxy, you can revoke or change your voting instructions, but we must receive your instructions to change or revoke your vote in time, or you can vote in person instead, as noted below.

Registered shareholders

If you voted online or by phone, submit new voting instructions. Your new instructions will revoke your earlier instructions.

If you voted online, you can also use a proxy form to submit new voting instructions, as long as they are received at least 48 hours before the start of the meeting. Your new instructions will revoke your earlier instructions.

If you voted by fax or mail, you can use a proxy form to submit new voting instructions, as long as they are received at least 24 hours before the start of the meeting.

You can also:

•: send us notice in writing (from you or a person authorized to sign on your behalf). We must receive it by 6 p.m. MDT on May 7, 2013, or by 6 p.m. MDT on the business day before the meeting is reconvened if it was postponed or adjourned. Send your notice to the Corporate Secretary, Enbridge Inc., 3000, 425-1st Street S.W., Calgary, Alberta T2P 3L8 Fax: 1.403.231.5929;
•: give your notice to the chair of the meeting before the start of the meeting. If you give him the notice after the meeting has started, your new instructions will apply only to the items of business that haven't already been voted on; or
•: change your vote in any other manner permitted by law.

2013 Management information circular 6

If your common shares are owned by a corporation, your notice must be under a corporate seal or issued by an authorized officer of the company or its attorney.

You can send us your new instructions in any other manner permitted by law.

Non-registered shareholders

Contact your nominee to find out how to change or revoke your vote and the timing requirements.

Voting results

We need a simple majority (at least 50% plus one vote) of all votes cast to elect the nominated directors, appoint the auditors and approve our approach to executive compensation.

CIBC Mellon counts the votes and will only show us a proxy form if:
•  it is required by law;
•  there is a proxy contest; or
•  a shareholder has written comments on the proxy form that are clearly intended for Enbridge management.

Questions?

Contact our transfer agent

CIBC Mellon
1.800.387.0825
www.canstockta.com

ELECTING OUR DIRECTORS

On February 27, 2012, after receiving Mr. Daniel's letter advising that he would be retiring on or before the end of 2012, the Board resolved to increase the size of the Board from 12 to 13 directors and appointed Mr. Monaco to the Board. Mr. Monaco was also appointed President at that time. Mr. Daniel retired as Chief Executive Officer and from the Board effective September 30, 2012, and Mr. Monaco was appointed President & Chief Executive Officer effective October 1, 2012. All 12 current directors are standing for re-election to the Board. You can vote for all of them, vote for some and withhold your vote for others, or withhold your votes for all of them. Unless you instruct otherwise, the Enbridge proxyholders will vote for electing each of the nominated directors.

All of the directors are independent, except for Al Monaco, our President & Chief Executive Officer. There is no family relationship between any of the nominated directors.

Shareholders elect directors to the Board for a term of one year, until the end of the next annual meeting.

Our policy on majority voting

If a director receives more withheld votes than for votes, he or she will offer to resign. The Governance Committee will make a recommendation to the Board to:

•: accept the resignation;
•: ask the director to continue serving but address the issue; or
•: reject the resignation.

The director will not participate in any Board or Board Committee deliberations on the matter. If the Board accepts the director's resignation, it can appoint a new director to fill the vacancy. The Board must promptly disclose its final decision in a press release.

Board size

Our articles allow us to have up to 15 directors. The Board believes that its current size of 12 directors provides the skills and experience we need to make decisions effectively and meets the needs of the standing Board Committees.

The composition of the Board may also be affected by our agreement with Noverco Inc. (Noverco) and Gaz Métro inc. As long as Noverco or its subsidiaries own at least 8% of our total outstanding shares, Noverco may nominate one or more directors to the Board, in direct proportion to its share ownership relative to the total Enbridge shares outstanding. Noverco and its subsidiaries own less than 6% of our total outstanding shares, so this right currently does not apply.

7 ENBRIDGE INC.

Director profiles

The profiles that follow provide information about the nominated directors, including their background, areas of expertise, current directorships, securities held and the Board Committees they sit on.


David A. Arledge

Age 68 Naples, Florida, USA Independent Director since January 1, 2002 Chair of the Board since May 2005 Latest date of retirement May 2020 Areas of expertise Energy Finance Oil & gas Pipelines Regulated businesses

From 1983 until 2001, Mr. Arledge was principally employed by Coastal Corporation (energy company) which merged in early 2001 with El Paso Corporation (integrated energy company). He held various executive positions in finance from 1983 to 1993, including Senior Vice President, Finance & Chief Financial Officer, and from 1993 to 2001 held many senior executive and operating positions, retiring in 2001 as Chair, President & Chief Executive Officer.

Enbridge Board/Board Committee memberships			2012 meeting attendance1

Board of Directors			10 out of 10	(100%)
Audit, Finance & Risk2			8 out of 10	(80%)
Corporate Social Responsibility2			4 out of 4	(100%)
Governance2			4 out of 4	(100%)
Human Resources & Compensation2			6 out of 6	(100%)
Total			32 out of 34	(96%)

Enbridge securities held3
Year	Enbridge shares	DSUs4	Total market value of Enbridge shares and DSUs5	Minimum required6

2013	32,600	43,511	$3,492,734	$630,000
2012	32,600	39,348	$2,754,889	$420,000

Other public and private company board/board committee memberships7

Aviva USA Corp.			Chair, board of directors
(private insurance company that is a subsidiary of Aviva plc, a public company)


James J. Blanchard

Age 70 Beverly Hills, Michigan, USA Independent Director since January 25, 1999 Latest date of retirement May 2018 Areas of expertise Government Legal Environment Safety & sustainability Governance

Gov. Blanchard has practiced law with DLA Piper US, LLP in Michigan and Washington, D.C. since 1996 and is the Chair Emeritus, Government Affairs of that firm. From 1993 to 1996, Gov. Blanchard served as the United States Ambassador to Canada. He was Governor of Michigan for eight years and served eight years in the United States Congress.

Enbridge Board/Board Committee memberships			2012 meeting attendance1

Board of Directors			10 out of 10	(100%)
Corporate Social Responsibility (Chair)			4 out of 4	(100%)
Governance			4 out of 4	(100%)
Total			18 out of 18	(100%)

Enbridge securities held3
Year	Enbridge shares	DSUs4	Total market value of Enbridge shares and DSUs5	Minimum required6

2013	10,977	94,563	$4,843,231	$630,000
2012	25,770	89,016	$4,395,156	$420,000

Other public and private company board/board committee memberships7,8.9

Meridian International Center			Chair, board of trustees
(private, non-profit institution that promotes international understanding)			Chair, executive committee

National Archives Foundation (US)			Member, board of directors
(not-for-profit)			Vice President

The Canada-United States Law Institute			U.S. Co-Chair
(not-for-profit)

2013 Management information circular 8


J. Lorne Braithwaite

Age 71 Thornhill, Ontario, Canada Independent Director since May 3, 1989 Latest date of retirement May 2017 Areas of expertise Finance Mergers & acquisitions Governance Human resources Real estate Retail

Mr. Braithwaite has been the President & Chief Executive Officer of Build Toronto Inc., an economic development corporation, since 2009. From 1978 to 2001 he was President & Chief Executive Officer of Cambridge Shopping Centres Limited (developer and manager of retail shopping malls in Canada).

Enbridge Board/Board Committee memberships			2012 meeting attendance1

Board of Directors			10 out of 10	(100%)
Corporate Social Responsibility10			2 out of 2	(100%)
Governance10			2 out of 2	(100%)
Human Resources & Compensation			6 out of 6	(100%)
Total			20 out of 20	(100%)

Enbridge securities held3
Year	Enbridge Shares11	DSUs4	Total market value of Enbridge shares and DSUs5	Minimum required6

2013	86,090	36,336	$5,618,129	$630,000
2012	84,760	33,989	$4,546,899	$420,000

Other public and private company board/board committee memberships7

Enbridge Gas Distribution Inc.			Director
(public utilities company that is a wholly-owned subsidiary of Enbridge)			Member, audit, finance & risk committee

Canada Post Pension Plan (private pension plan)			Chair, investment advisory committee


J. Herb England

Age 66 Naples, Florida, USA Independent Director since January 1, 2007 Latest date of retirement May 2022 Areas of expertise Accounting and auditing Finance Mergers & acquisitions Industrial relations

Mr. England has been Chair & Chief Executive Officer of Stahlman-England Irrigation Inc. (contracting company) in southwest Florida since 2000. From 1993 to 1997, Mr. England was the Chair, President & Chief Executive Officer of Sweet Ripe Drinks Ltd. (fruit beverage manufacturing company). Prior to 1993, Mr. England held various executive positions with John Labatt Limited (brewing company) and its operating companies, including the position of Chief Executive Officer of Labatt Brewing Company – Prairie Region (brewing company), Catelli Inc. (food manufacturing company) and Johanna Dairies Inc. (dairy company). In 1993, Mr. England retired as Senior Vice President, Finance and Corporate Development & Chief Financial Officer of John Labatt Limited.

Enbridge Board/Board Committee memberships			2012 meeting attendance1

Board of Directors			10 out of 10	(100%)
Audit, Finance & Risk			10 out of 10	(100%)
Governance12			2 out of 2	(100%)
Human Resources & Compensation12			3 out of 3	(100%)
Total			25 out of 25	(100%)

Enbridge securities held3
Year	Enbridge shares13	DSUs4	Total market value of Enbridge shares and DSUs5	Minimum required6

2013	2,120	43,305	$2,084,553	$630,000
2012	2,120	39,460	$1,592,098	$420,000

Other public and private company board/board committee memberships7

Enbridge Energy Company, Inc.			Director
(a private company that is an indirect, wholly owned subsidiary of Enbridge and general partner of Enbridge Energy Partners, L.P.)			Chair, audit committee

Enbridge Energy Management, L.L.C.			Director
(public management company in which Enbridge holds an interest)			Chair, audit committee

FuelCell Energy, Inc.			Director
(public fuel cell company in which Enbridge holds a small interest)			Member, audit & finance committee
			Chair, compensation committee

Goodwood Fund 2.0 Ltd. (private registered regulated mutual fund)			Director

Stahlman-England Irrigation Inc.			Chair, board of directors
(private contracting company)			Chief executive officer

9 ENBRIDGE INC.


Charles W. Fischer

Age 62 Calgary, Alberta, Canada Independent Director since July 28, 2009 Latest date of retirement May 2025 Areas of expertise Business management Energy Engineering Mergers & acquisitions Oil & gas

Mr. Fischer was the President & Chief Executive Officer of Nexen Inc. (oil and gas company) from 2001 to 2008. Since 1994, Mr. Fischer held various executive positions within Nexen Inc., including the positions of Executive Vice President & Chief Operating Officer in which he was responsible for all Nexen's conventional oil and gas business in Western Canada, the US Gulf Coast and all international locations, as well as oil sands, marketing and information systems activities worldwide. Prior thereto, Mr. Fischer held positions with Dome Petroleum Ltd., Hudson's Bay Oil & Gas Ltd., Bow Valley Industries Ltd., Sproule Associates Ltd. and Encor Energy Ltd.

Enbridge Board/Board Committee memberships			2012 meeting attendance1

Board of Directors			9 out of 10	(90%)
Audit, Finance & Risk14			3 out of 3	(100%)
Corporate Social Responsibility14			2 out of 2	(100%)
Human Resources & Compensation			6 out of 6	(100%)
Total			20 out of 21	(98%)

Enbridge securities held3
Year	Enbridge shares15	DSUs4	Total market value of Enbridge shares and DSUs5	Minimum required6

2013	8,000	12,922	$960,111	$630,000
2012	8,000	9,919	$686,119	$420,000

Other public and private company board/Board committee memberships7

Enbridge Commercial Trust (subsidiary of Enbridge Income Fund)			Trustee

Enbridge Income Fund Holdings Inc. (public holding company in which Enbridge holds an interest)			Director

Pure Technologies Ltd.			Director
(public technology company)			Member, audit and compensation committees

Summerland Energy Inc. (private oil and gas company)			Chair, board of directors

Alberta Innovates – Energy and Environment Solutions			Director
(not-for-profit – energy and environmental research)			Member, human resources & compensation committee

Climate Change and Emission Management Corporation (not-for-profit – energy and environmental research)			Director

University of Calgary (Canadian University)			Member, audit committee of the Board of Governors


V. Maureen Kempston Darkes

Age 64 Lauderdale-by-the-Sea, Florida, USA Independent Director since November 2, 2010 Latest date of retirement May 2023 Areas of expertise Governance Government and public policy Growth initiatives International business Legal

Ms. Kempston Darkes is the retired Group Vice President and President Latin America, Africa and Middle East, General Motors Corporation (automotive corporation and vehicle manufacturer). From 1994 to 2001, she was the President and General Manager of General Motors of Canada Limited and Vice President of General Motors Corporation.

Enbridge Board/Board Committee memberships			2012 meeting attendance1

Board of Directors			10 out of 10	(100%)
Corporate Social Responsibility			4 out of 4	(100%)
Human Resources & Compensation			6 out of 6	(100%)
Total			20 out of 20	(100%)

Enbridge securities held3
Year	Enbridge shares	DSUs4	Total market value of Enbridge shares and DSUs5	Minimum required6

2013	12,705	9,682	$1,027,339	$630,000
2012	10,000	8,089	$692,628	$420,000

Other public and private company board/board committee memberships7,16

Brookfield Asset Management Inc.			Director
(global asset management company)			Chair, risk management committee Member, management, resources & compensation committee

Canadian National Railway Company			Director
(public railway company)			Chair, environment, safety & security committee Member, audit, human resources & compensation and strategic planning committees and member of the investment committee of CN's pension trust funds

Irving Oil Company Limited			Director
(private oil company)			Chair, audit & risk management committee Member, human resources & compensation committee

Balfour Beatty plc			Director
(infrastructure services company publicly listed in the UK)			Member, nomination committee Member, business practices committee

2013 Management information circular 10


David A. Leslie, F.C.A.

Age 69 Toronto, Ontario, Canada Independent Director since July 26, 2005 Latest date of retirement May 2019 Areas of expertise Accounting and auditing Governance Corporate tax Finance Mergers & acquisitions

Mr. Leslie was the Chair & Chief Executive Officer of Ernst & Young LLP (private accounting firm) from 1999 until June 2004 and was a partner and held various senior management positions with the firm from 1977 to 2004.

Enbridge Board/Board Committee memberships			2012 meeting attendance1

Board of Directors			10 out of 10	(100%)
Audit, Finance & Risk (Chair)			10 out of 10	(100%)
Governance			4 out of 4	(100%)
Total			24 out of 24	(100%)

Enbridge securities held3
Year	Enbridge shares	DSUs4	Total market value of Enbridge shares and DSUs5	Minimum required6

2013	10,456	45,722	$2,578,008	$630,000
2012	10,179	38,526	$1,864,914	$420,000

Other public and private company board/board committee memberships7,17

Enbridge Gas Distribution Inc.			Director,
(public utilities company that is a wholly-owned subsidiary of Enbridge)			Chair, audit, finance & risk committee

Crombie REIT			Director
(public real estate investment trust)			Chair, audit committee

Empire Company Limited			Director
(public food retail and related real estate company)			Chair, audit committee and member, oversight, nominating & governance committee

Sobeys Inc.			Director
(food merchandising company that is a wholly-owned subsidiary of Empire Company Limited)			Chair, audit committee and member, oversight, nominating & governance committee

IMRIS Inc.			Director
(public surgical imaging systems company)			Chair, audit and governance committee

MaRS Innovation (not-for-profit business development organization)			Director


Al Monaco

Age 53 Calgary, Alberta, Canada Not independent Director since February 27, 2012 Latest date of retirement May 2035 Areas of expertise Business management Energy Finance Oil & gas Pipelines

Mr. Monaco joined Enbridge in 1995. He has been President & Chief Executive Officer of Enbridge since October 1, 2012 and has served as President of Enbridge since February 27, 2012.

Enbridge Board/Board Committee memberships18			2012 meeting attendance1

Board of Directors			7 out of 7	(100%)

Enbridge securities held3
Year	Enbridge shares19	Stock options	Total market value of Enbridge shares (excluding stock options)5	Minimum required20

2013	118,596	2,458,700	$5,442,370	–
2012	96,303	1,170,900	$3,687,442	–

Other public and private company board/board committee memberships7

Enbridge Pipelines Inc. (public pipeline company that is a wholly-owned subsidiary of Enbridge)			Director and Chair

Enbridge Gas Distribution Inc. (public utilities company that is a wholly-owned subsidiary of Enbridge)			Director

University of Calgary (Canadian university)			Member, investment committee of the Board of Governors
			Member, Dean's advisory board, Faculty of Medicine

American Petroleum Institute (trade association)			Director

C.D. Howe Institute (public policy institute)			Director

11 ENBRIDGE INC.


George K. Petty

Age 71 San Luis Obispo, California, USA Independent Director since January 2, 2001 Latest date of retirement May 2017 Areas of expertise Telecommunications Finance Mergers & acquisitions Business management Energy Governance Regulated businesses

Mr. Petty was President & Chief Executive Officer of Telus Corporation (telecommunications company) from 1994 to 1999. Prior thereto he was Vice President of Global Business Service for AT&T (telecommunications company) and Chair of the Board of directors of World Partners, the Global Telecom Alliance.

Enbridge Board/Board Committee memberships			2012 meeting attendance1

Board of Directors			10 out of 10	(100%)
Audit, Finance & Risk			10 out of 10	(100%)
Governance (Chair)21			2 out of 2	(100%)
Corporate Social Responsibility21			2 out of 2	(100%)
Total			24 out of 24	(100%)

Enbridge securities held3
Year	Enbridge shares22	DSUs4	Total market value of Enbridge shares and DSUs5	Minimum required6

2013	1,894	50,220	$2,391,511	$630,000
2012	26,594	47,464	$2,835,681	$420,000

Other public and private company board/board committee memberships7


Charles E. Shultz

Age 73 Calgary, Alberta, Canada Independent Director since December 1, 2004 Latest date of retirement May 2015 Areas of expertise Energy Oil & gas Human resources Mining Pipelines Governance

Mr. Shultz has been the Chair & Chief Executive Officer of Dauntless Energy Inc. (private oil and gas company) since he formed it in 1995. From 1990 to 1995, Mr. Shultz served as President & Chief Executive Officer of Gulf Canada Resources Limited (oil and gas company).

Enbridge Board/Board Committee memberships			2012 meeting attendance1

Board of Directors			10 out of 10	(100%)
Audit, Finance & Risk			10 out of 10	(100%)
Human Resources & Compensation			6 out of 6	(100%)
Total			26 out of 26	(100%)

Enbridge securities held3
Year	Enbridge shares	DSUs4	Total market value of Enbridge shares and DSUs5	Minimum required6

2013	31,657	37,454	$3,171,504	$630,000
2012	28,466	35,075	$2,432,985	$420,000

Other public and private company board/board committee memberships7

Enbridge Pipelines Inc. (public pipeline company that is a wholly-owned subsidiary of Enbridge)			Director

Canadian Oil Sands Limited			Director
(public oil and gas company)			Member, reserves, marketing, operations & environmental health & safety committee

Newfield Exploration			Interim Lead Director
(public oil and gas company)			Member, audit committee

2013 Management information circular 12


Dan C. Tutcher

Age 64 Houston, Texas, USA Independent Director since May 3, 2006 Latest date of retirement May 2024 Areas of expertise Deregulated businesses Energy Engineering Finance Mergers & acquisitions Oil & gas Pipelines Regulated businesses Utilities

Since its inception in 2007, Mr. Tutcher has been a Principal in Center Coast Capital Advisors L.P. He was the Group Vice President, Transportation South of Enbridge, as well as President of Enbridge Energy Company, Inc. (general partner of Enbridge Energy Partners, L.P. and an indirect, wholly-owned subsidiary of Enbridge) and Enbridge Energy Management, L.L.C. (management company in which Enbridge holds a 17.2% interest) from May 2001 until retirement on May 1, 2006. From 1992 to May 2001, he was the Chair of the Board of directors, President & Chief Executive Officer of Midcoast Energy Resources, Inc.

Enbridge Board/Board Committee memberships			2012 meeting attendance1

Board of Directors			10 out of 10	(100%)
Corporate Social Responsibility			4 out of 4	(100%)
Governance (Chair)23			4 out of 4	(100%)
Total			18 out of 18	(100%)

Enbridge securities held3
Year	Enbridge shares24	DSUs4	Total market value of Enbridge shares and DSUs5	Minimum required6

2013	630,711	49,766	$31,227,090	$630,000
2012	616,856	42,966	$25,264,584	$420,000

Other public and private company board/board committee memberships7

St. Luke's Episcopal Hospital (US hospital)			Director

Texas Heart Institute (not-for-profit organization)			Director


Catherine L. Williams

Age 62 Calgary, Alberta, Canada Independent Director since November 1, 2007 Latest date of retirement May 2026 Areas of expertise Finance Energy Oil & gas Mergers & acquisitions Business management

Ms. Williams was the Chief Financial Officer for Shell Canada Limited (oil and gas) from 2003 to 2007. Prior to that, she held various positions with Shell Canada Limited, Shell Europe Oil Products, Shell Canada Oil Products and Shell International (oil and gas companies) from 1984 to 2007.

Enbridge Board/Board Committee memberships			2012 meeting attendance1

Board of Directors			10 out of 10	(100%)
Audit, Finance & Risk			10 out of 10	(100%)
Human Resources & Compensation (Chair)			6 out of 6	(100%)
Total			26 out of 26	(100%)

Enbridge securities held3
Year	Enbridge shares	DSUs4	Total market value of Enbridge shares and DSUs5	Minimum required6

2013	28,841	22,066	$2,366,122	$630,000
2012	25,394	18,616	$1,685,143	$420,000

Other public and private company board/board committee memberships6

Enbridge Pipelines Inc. (public pipeline company that is a wholly-owned subsidiary of Enbridge)			Director

Alberta Investment Management Corporation			Director
(Alberta Crown corporation)			Chair, audit committee

1: Percentages are rounded up to the nearest whole number.
2: Mr. Arledge is not a member of any Board Committee, but he attends most of their meetings because he is the Chair of the Board.
3: Information about beneficial ownership and about securities controlled or directed by our proposed directors is provided by the nominees and is as at March 2, 2012 and March 5, 2013.
4: DSU's refer to deferred share units and are defined on page 36 of this circular.
5: Total market value = number of common shares or deferred share units × closing price of Enbridge common shares on the Toronto Stock Exchange (TSX) of $38.29 on March 2, 2012 and $45.89 on March 5, 2013. Amounts are rounded to the nearest dollar.
6: Effective January 1, 2013, Directors must hold at least three times their annual Board retainer, or $630,000, in DSUs or Enbridge shares and meet that requirement within five years of becoming a director on our Board.
7: Public means a corporation or trust that is a reporting issuer in Canada, a registrant in the US or both. Private means a corporation or trust that is not a reporting issuer or registrant. Not-for-profit means a corporation, society or other entity organized for a charitable, civil or other social purpose which does not generate profits for its members.

13 ENBRIDGE INC.

8: The Ontario Securities Commission, the British Columbia Securities Commission and the autorité des Marchés financiers issued a management cease trade order against insiders of Bennett Environmental Inc. on April 10, 2006, and another cease trade order on April 24, 2006 after Bennett failed to file its annual financial statements and related MD&A for the year ended December 31, 2005. The orders prevented certain Bennett directors, officers and insiders, including Governor Blanchard, from trading Bennett securities until the commissions received the documents. Bennett filed the documents on May 30, 2006 and the management cease trade order was revoked on June 19, 2006. Governor Blanchard was a director of Bennett until August 7, 2006.
9: On May 31, 2004 and again on April 10, 2006, certain directors, senior officers and certain current and former employees of Nortel Networks Corporation and Nortel Networks Limited were prohibited from trading in the securities of Nortel Networks Corporation and Nortel Networks Limited pursuant to management cease trade orders issued by the Ontario Securities Commission and certain other provincial securities regulators in connection with delays in the filing of certain financial statements. Following the filing of the required financial statements, the Ontario Securities Commission and subsequently the other provincial securities regulators lifted such cease trade orders effective June 21, 2005 and June 8, 2006 respectively. Governor Blanchard was a director of Nortel Networks Corporation until June 29, 2005. At no time did the above noted cease trade orders apply to Governor Blanchard.
10: Mr. Braithwaite ceased being a member of the Corporate Social Responsibility Committee in May 2012 and did not attend meetings of the Committee after that time. Mr. Braithwaite was appointed to the Governance Committee in May 2012 and attended all meetings of the Committee from the time of his appointment.
11: Mr. Braithwaite also owns 12,289 shares of Enbridge Income Fund Holdings Inc.
12: Mr. England ceased being a member of the Governance Committee in May 2012 and did not attend meetings of the Committee after that time. Mr. England was appointed to the Human Resources & Compensation Committee in May 2012 and attended all meetings of the Committee from the time of his appointment.
13: Mr. England also owns 7,876 units of Enbridge Energy Partners, L.P.
14: Mr. Fischer ceased being a member of the Corporate Social Responsibility Committee in May 2012 and did not attend meetings of the Committee after that time. Mr. Fischer was appointed to the Audit, Finance & Risk Committee in May 2012 and attended all meetings of the Committee from the time of his appointment.
15: Mr. Fischer also owns 25,000 shares of Enbridge Income Fund Holdings Inc.
16: Ms. Kempston Darkes was an executive officer of General Motors Corporation (GM) from January 1, 2002 to December 1, 2009. GM filed for bankruptcy protection under Chapter 11 of the US Bankruptcy Code on June 1, 2009. None of the operations for which she was directly responsible in Latin America, Africa and the Middle East were included in the bankruptcy filing. GM emerged from bankruptcy protection on July 10, 2009 in a reorganization in which a new entity acquired GM's most valuable assets.
17: Mr. Leslie was on the board of CanWest Global Communications Corp. from March 26, 2007 to January 14, 2009. On October 6, 2009, CanWest Global Communications Corp. voluntarily entered into (and successfully obtained) an order from the Ontario Superior Court of Justice (Commercial Division), commencing proceedings under the Companies' Creditors Arrangement Act.
18: Mr. Monaco was appointed to the Board on February 27, 2012. Mr. Monaco is not a member of any Board Committee. He attends Board Committee meetings at the request of the Board.
19: Mr. Monaco also owns 8,150 shares of Enbridge Income Fund Holdings Inc.
20: As President & Chief Executive Officer, Mr. Monaco is required to hold Enbridge shares equal to five times his base salary (see page 47). Mr. Monaco is not required to hold Enbridge shares as a director.
21: Mr. Petty ceased being a member of the Governance Committee in May 2012 and did not attend Committee meetings after such time. Mr. Petty was appointed to the Corporate Social Responsibility Committee in May 2012 and attended all meetings of the Committee from the time of his appointment.
22: Mr. Petty also owns 9,266 shares of Enbridge Energy Management, L.L.C. and 5,234 units of Enbridge Energy Partners, L.P.
23: Mr. Tutcher was appointed chair of the Governance Committee in May 2012.
24: Mr. Tutcher also owns 69,892 shares of Enbridge Energy Management, L.L.C. and 40,000 units of Enbridge Energy Partners, L.P.

2013 Management information circular 14

Director independence


	Director nominees	Independent	Non-Independent	Reason for non-independence

David A. Arledge		ü

James J. Blanchard		ü

J. Lorne Braithwaite		ü

J. Herb England		ü

Charles W. Fischer		ü

V. Maureen Kempston Darkes		ü

David A. Leslie		ü

Al Monaco			ü	President & Chief Executive Officer of the company

George K. Petty		ü

Charles E. Shultz		ü

Dan C. Tutcher		ü

Catherine L. Williams		ü

Board Committee participation


	Director	Audit, Finance & Risk Committee	Corporate Social Responsibility Committee	Governance Committee	Human Resources & Compensation Committee

Management directors – not independent

Al Monaco

Outside directors – independent

David A. Arledge1

James J. Blanchard			Committee chair	ü

J. Lorne Braithwaite				ü	ü

J. Herb England2		ü			ü

Charles W. Fischer		ü			ü

V. Maureen Kempston Darkes			ü		ü

David A. Leslie2		Committee chair		ü

George K. Petty		ü	ü

Charles E. Shultz		ü			ü

Dan C. Tutcher			ü	Committee chair

Catherine L. Williams2		ü			Committee chair

1: Mr. Arledge is not a member of any of the committees of the Board. He attends most of the Committee meetings in his capacity as Chair of the Board.
2: Mr. Leslie, Mr. England and Ms. Williams each qualify as an audit committee financial expert, as defined by the US Securities Exchange Act of 1934. The Board has also determined that all the members of the Audit, Finance & Risk Committee are financially literate, according to the meaning of National Instrument 52-110 – Audit Committees (NI 52-110) and the rules of the New York Stock Exchange (NYSE).

Board and Board Committee meetings


	Board/Committee	In-camera sessions	Total number of meetings	Overall attendance

Board		7	10	99%

Audit, Finance & Risk Committee		7	10	97%

Corporate Social Responsibility Committee		4	4	100%

Governance Committee		4	4	100%

Human Resources & Compensation Committee		6	6	100%

Total		28	34	99%

15 ENBRIDGE INC.

Director attendance


			Board Committee meetings

	Board of Directors meetings (10 meetings)		Audit, Finance & Risk (10 meetings)		Corporate Social Responsibility (4 meetings)		Governance (4 meetings)		Human Resources & Compensation (6 meetings)
	Number	%	Number	%	Number	%	Number	%	Number	%

David A. Arledge1	10	100	8	80	4	100	4	100	6	100

James J. Blanchard	10	100	–	–	4	100	4	100	–	–

J. Lorne Braithwaite2	10	100	–	–	2	100	2	100	6	100

Patrick D. Daniel3	8	100	–	–	–	–	–	–	–	–

J. Herb England4	10	100	10	100	–	–	2	100	3	100

Charles W. Fischer5	9	90	3	100	2	100	–	–	6	100

V. Maureen Kempston Darkes	10	100	–	–	4	100	–	–	6	100

David A. Leslie	10	100	10	100	–	–	4	100	–	–

Al Monaco6	7	100	–	–	–	–	–	–	–	–

George K. Petty7	10	100	10	100	2	100	2	100	–	–

Charles E. Shultz	10	100	10	100	–	–	–	–	6	100

Dan C. Tutcher	10	100	–	–	4	100	4	100	–	–

Catherine L. Williams	10	100	10	100	–	–	–	–	6	100

		99%		97%		100%		100%		100%

1: Mr. Arledge is not a member of any Board Committee, but he attends most of their meetings because he is the Chair of the Board.
2: Mr. Braithwaite was appointed as a member of the Governance Committee and ceased being a member of the Corporate Social Responsibility Committee in May 2012.
3: Mr. Daniel retired as Chief Executive Officer and Director effective September 30, 2012. He was not a member of any Board Committee but attended Board Committee meetings at the request of the Board until his retirement.
4: Mr. England was appointed as a member of the Human Resources and Compensation Committee and ceased being a member of the Governance Committee in May 2012.
5: Mr. Fischer was appointed a member of the Audit Finance & Risk Committee and ceased being a member of the Corporate Social Responsibility Committee in May 2012.
6: Mr. Monaco joined the Board on February 27, 2012. Mr. Monaco is not a member of any Board Committee. He attends Board Committee meetings at the request of the Board.
7: Mr. Petty was appointed to the Corporate Social Responsibility Committee and ceased being a member of the Governance Committee in May 2012.

2013 Management information circular 16

Mix of skills and experience


	Skill/experience	Number of directors with significant senior level experience

Managing and leading growth Experience driving strategic direction and leading growth of an organization.		12

International Experience working in a major organization with global operations where Enbridge is or may be active.		10

Chief executive officer/senior officer Experience as a chief executive officer or senior officer of a publicly listed company or major organization.		12

Governance/board Experience as a board member of a publicly listed company or major organization.		12

Operations Experience in the oil and gas/energy (including pipelines) industries, and knowledge of markets, financials, operational issues, regulatory concerns and technology.		7

Sustainable development Understanding the elements of sound sustainable development practices and their relevance to corporate success.		10

Marketing expertise Marketing experience in the energy marketing industry combined with a strong knowledge of market participants.		5

Human resources/compensation Strong understanding of compensation, benefit and pension programs, legislation and agreements, with specific expertise in executive compensation programs.		10

Investment banking/mergers & acquisitions Experience in investment banking or in major mergers and acquisitions.		9

Financial literacy Experience in financial accounting and reporting and corporate finance, especially with respect to debt and equity markets and familiarity with internal financial controls, Canadian or US generally accepted accounting principles and/or international financial reporting standards.		12

Information technology Experience in information technology with major implementations of management systems.		5

Health, safety, environment and social responsibility Thorough understanding of industry regulations and public policy and leading practices in the areas of workplace safety, health, the environment and social responsibility.		8

Government relations Experience in (or a strong understanding of) the workings of government and public policy in Canada and the US.		9

Emerging sectors Experience in sectors which Enbridge hopes to develop a presence, including liquefied natural gas, power generation and new energy technologies.		7

Continuing Education


	Date	Topic	Presented/hosted by	Who attended

March 19, 2012		"The Quest" – Energy, Security and the Remaking of the Modern World	Daniel Yergin	All members of the Board

August 1, 2012		North American Crude and Product Markets	PIRA Energy Group	All members of the Board

September 6, 2012		Board tour of ECHO terminal and Lyondell Refinery and Board helicopter tour of the Houston Ship Channel and Port of Houston from Ellington Field	Enbridge Inc.	All members of the Board other than Gov. Blanchard

November 6, 2012		Energy Marketing Business Update	Enbridge Inc.	All members of the Board

17 ENBRIDGE INC.

Interlocking relationships


	Directors	Served together on these boards	Served on these committees

J. Lorne Braithwaite		Enbridge Gas Distribution Inc.1	Audit, finance & risk committee
David A. Leslie			Chair of the audit, finance & risk committee
Al Monaco			–

Al Monaco		Enbridge Pipelines Inc.1	–
Charles E. Shultz			–
Catherine L. Williams			–

1: Enbridge Gas Distribution Inc. and Enbridge Pipelines Inc. are considered public companies because they are reporting issuers in Canada, but they do not have any equity securities that are publicly held. They are both wholly-owned subsidiaries of Enbridge.

Director tenure

The graph below shows our director tenure as of March 5, 2013. The average tenure is 8.5 years.

APPOINTING OUR AUDITORS

You will vote on appointing Enbridge's auditors. You may vote for the reappointment of our auditors or withhold your vote. The Board, on the recommendation of the Audit, Finance & Risk Committee, proposes that PwC be reappointed as auditors and that you vote for the reappointment of our auditors.

If PwC is reappointed, they will serve as our auditors until the end of the next annual meeting of shareholders. PwC and its predecessor firm, Price Waterhouse, have been our auditors since 1992 and auditors for Enbridge Pipelines Inc., our wholly-owned subsidiary, since 1949.

PwC is a participating audit firm with the Canadian Public Accountability Board, as required under the Canadian Securities Administrators' National Instrument 52-108 – Auditor Oversight.

2013 Management information circular 18

Auditor Independence

Auditor independence is essential to the integrity of our financial statements and PwC has confirmed its status as independent within the meaning of the Canadian and US securities rules.

We are subject to Canadian securities regulations (NI 52-110 and National Policy 58-201 – Corporate Governance Guidelines (NP 58-201), the US Sarbanes-Oxley Act of 2002 (Sarbanes-Oxley) and the accounting and corporate governance rules adopted by the US Securities and Exchange Commission under Sarbanes-Oxley, which specify certain services that external auditors cannot provide.

We comply with these Canadian and US rules. We believe, however, that some non-audit services, like tax compliance, can be delivered more efficiently and economically by our external auditors. To maintain auditor independence, our Audit, Finance & Risk Committee must pre-approve all audit and non-audit services. It is also responsible for overseeing the audit work performed by PwC.

The Audit, Finance & Risk Committee reviews our external auditors' qualifications and independence once a year. Their review includes formal written statements that describe any relationships between the auditors, their affiliates and Enbridge that could affect the auditors' independence and objectivity.

Auditors' fees

The table below shows the services PwC provided to Enbridge in 2012, by category. It also shows the fees PwC billed for these services in 2011 and 2012.



		2012		20111	Description of fee category

Audit fees	$	10,919,000	$	10,916,624	Represents the aggregate fees for audit services.

Audit-related fees		927,480		336,496	Represents the aggregate fees for assurance and related services by the company's auditors that are reasonably related to the performance of the audit or review of the company's financial statements and are not included under "Audit fees". During fiscal 2012 and 2011, the services provided in this category included due diligence related to prospectus offerings and other items.

Tax fees		1,128,846		1,276,159	Represents the aggregate fees for professional services rendered by the company's auditors for tax compliance, tax advice and tax planning.

All other fees		912,555		670,304	Represents the aggregate fees for products and services provided by the company's auditors other than those services reported under "Audit fees", "Audit-related fees" and "Tax fees". These fees include those related to US GAAP, Canadian Public Accountability Board fees, French translation work and process reviews.

Total fees	$	13,887,881	$	13,199,583

1: Comparative figures presented above have been restated to include fees for Enbridge Energy Partners, L.P. (EEP), which is now consolidated within the company's consolidated financial statements prepared in accordance with US GAAP. Fees billed to EEP are for services provided by the US affiliate of the company's auditors.

You can find information about the roles and responsibilities of the Audit, Finance & Risk Committee starting on page 28 of this circular and details about the committee's pre-approval policies and procedures beginning on page 40 of our annual information form for the year ended December 31, 2012 (available online at www.enbridge.com and www.sedar.com).

19 ENBRIDGE INC.

HAVING A "SAY ON PAY"

Maintaining high standards of corporate governance involves responding to emerging best practices.

We announced in February 2010 that we would have an advisory vote on executive compensation starting at our 2011 annual meeting. The Board decided to hold an advisory vote after lengthy discussions on the matter. In addition, several Board members met with the Canadian Coalition for Good Governance (CCGG) about governance practices and shareholder engagement. At the 2012 annual and special meeting of shareholders, shareholders voted 94% in favour of our approach to executive compensation. In August 2012, the Board decided to again hold an advisory vote on executive compensation at the 2013 annual meeting.

While this vote is non-binding, it gives shareholders an opportunity to provide important input to our Board.

As a shareholder, you will be asked to vote for or against, or you may abstain from voting on our approach to executive compensation through the following resolution:

Be it resolved, on an advisory basis and not to diminish the role and responsibilities of the Board of Directors, that the shareholders accept the approach to executive compensation disclosed in our management information circular dated March 5, 2013, delivered in advance of the 2013 annual meeting of shareholders on May 8, 2013.

The Board will take the results of this vote into account when it considers future compensation policies and issues. We will also examine the level of shareholder interest and the comments we receive and consider the best approach and timing for soliciting feedback from shareholders on our approach to executive compensation in the future.

SHAREHOLDER PROPOSALS

We received no shareholder proposals for consideration at the meeting.

Under the Canada Business Corporations Act, which governs Enbridge, we must receive shareholder proposals by December 5, 2013 to consider them for inclusion in the management information circular and proxy for the 2014 annual meeting of shareholders, which is expected to be held on May 7, 2014.

We will post the results of this year's votes and the other items of business on our website (www.enbridge.com) following the shareholders' meeting.

2013 Management information circular 20

2. Governance

OUR GOVERNANCE PRACTICES

Sound governance means sound business. At Enbridge, we believe good governance is important for our shareholders, our employees and our company.

We have a comprehensive system of stewardship and accountability that follows best practices and meets the requirements of all rules, regulations and policies that apply.

This section discusses our governance philosophy, policies and practices. It also describes the role and functioning of our Board and the four Board Committees.

You can find more information about governance in our annual information form for the year ended December 31, 2012. Our articles and by-laws also set out policies and practices that govern our business activities. These are all available on our website (www.enbridge.com).

Regulations, rules and standards

Enbridge is listed on the TSX and the NYSE and we are subject to a range of governance regulations, rules and standards:

Canada

•: National Instrument 58-101 – Disclosure of Corporate Governance Practices;
•: NP 58-201;
•: NI 52-110; and
•: Canada Business Corporations Act.

As a "foreign private issuer" under US securities laws, we are generally permitted to comply with Canadian corporate governance guidelines and rules, rather than those that apply to US listed corporations.

The NYSE rules, however, require us to disclose how we comply with US corporate governance standards and where our practices are different. You can find this document on our website (http://www.enbridge.com/ InvestorRelations/ CorporateGovernance/ USCompliance.aspx). We must also comply with the audit committee requirements under Rule 10A-3 of the US Securities Exchange Act of 1934. See Audit, Finance & Risk Committee in our annual information form for the year ended December 31, 2012 for a summary of these requirements.

As of the date of this circular, the Board believes we are in full compliance with all Canadian and US corporate governance regulations, rules and standards that apply to us.

A CULTURE OF ETHICAL CONDUCT

A strong culture of ethical conduct is central to governance at Enbridge.

Our statement on business conduct (available on our website at www.enbridge.com) is our formal statement of expectations on ethics. It applies to everyone at Enbridge and our subsidiaries, including our directors, officers and employees, as well as consultants and contractors who work with us.

It discusses what we expect in areas like:

•  complying with the law and undertakings;
•  interacting with landowners, customers, shareholders, employees and others;
•  protecting health, safety and the environment;

•  acquiring, using and maintaining assets;
•  using computers and communication devices;
•  conflicts of interest; and
•  proprietary, confidential and insider information.

The Board reviews the statement on business conduct at least once a year and updates it as necessary (it did not make any material changes in 2012).

21 ENBRIDGE INC.

All new employees at Enbridge and each of our subsidiaries must, as a condition of employment, sign a certificate of compliance indicating that they have read the statement on business conduct, understand it and agree to comply with it. Every year, all employees have to confirm that they have complied with it.

Directors must also certify that they agree with the statement on business conduct and will comply with it, both when they join our Board and every year they serve on it.

All employees were asked, through an electronic training and certification process, to certify their compliance with the statement on business conduct for the year ended December 31, 2012. As of the date of this circular, over 99% of Enbridge employees had certified compliance. For the first time, many of Enbridge's contract workers also participated in the online training and certification process this year.

Building awareness

We use online training to help raise awareness and reinforce our commitment to ethical conduct.

To date, we have developed online training programs on fraud awareness and the statement on business conduct.

The Chief Executive Officer and all members of the Board certified their compliance with the statement on business conduct in 2012.

Handling conflicts of interest

If a director or officer has a material interest in a transaction or agreement involving Enbridge, he or she must:
•  disclose the conflict or potential conflict;
•  choose not to participate in any discussions on the matter; and
•  abstain from voting on the matter at any Board meeting where it is being discussed or considered.

This approach is consistent with the requirements of the Canada Business Corporations Act.

Insider trading

Our insider trading and reporting guidelines, which were amended in March 2011, put restrictions on insiders and those in a special relationship with Enbridge when they trade Enbridge shares. The guidelines, which fulfill our obligations to stock exchanges, regulators and investors, include the following measures:

Material transactions

No informed person or nominated director (or any associate or affiliate) has or had a direct or indirect material interest in any Enbridge transaction in 2012 or in any proposed transaction that had or will have a material effect on Enbridge or any of our subsidiaries in the forseeable future.

•: having quarterly and annual trading blackout periods when financial results are being prepared and have not yet been publicly disclosed. These begin on the fifth day following the end of a quarter or fiscal year and end at the close of trading on the second trading day after we issue the news release or disclose our financial results;
•: publishing and communicating the dates for regular blackout periods;
•: encouraging all insiders to pre-clear transactions with the Corporate Secretary's office; and
•: prohibiting all directors, officers and employees from engaging in hedging transactions.

Whistleblower procedures

Our whistleblower procedures help uphold our strong values and preserve our culture of ethical business conduct.

We introduced whistleblower procedures to protect the integrity of our accounting, auditing and financial processes. We expanded the system in 2008 to include a broad range of matters relating to ethics and conduct. The whistleblower procedures were updated during 2012, primarily to reflect the fact that the Chief Compliance Officer has been designated as the person responsible for administering the procedures.

Employees can report concerns about financial or accounting irregularities or unethical conduct confidentially to the chair of the Audit, Finance & Risk Committee. All submissions may be made anonymously and any complaints submitted in a sealed envelope marked "private and strictly confidential" will be delivered to the committee chair unopened. Complaints can also be made anonymously using a toll-free number and a reporting system administered by an independent third party provider.

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At least once each quarter, the chair informs the Audit, Finance & Risk Committee about any complaints received (sooner if there is an urgent matter), discusses them with the Chief Compliance Officer and recommends how each complaint should be handled. The committee can hire independent advisors (outside legal counsel, independent auditors and others) to help investigate a matter. We pay for these costs.

THE ROLE OF THE BOARD

The Board is ultimately responsible for governance at Enbridge and for stewardship of the company. It has full power to oversee the management of our business and affairs.

It carries out many of its responsibilities through its four standing Board Committees:

•: Audit, Finance & Risk;
•: Corporate Social Responsibility;
•: Governance; and
•: Human Resources & Compensation.

The Board:

•: reviews and approves the strategic plan, provides guidance and monitors our progress;
•: monitors our risk management programs and helps us identify principal risks;
•: makes sure we have appropriate internal control and management systems in place to manage money, compliance and risk and that these systems are functioning appropriately; and
•: approves major projects, plans and initiatives that could materially affect the company.

The Board delegates day-to-day management of Enbridge to the Chief Executive Officer and senior management, although major capital expenditures, debt and equity financing arrangements and significant acquisitions and divestitures require Board approval.

Duties

The Board is responsible for overseeing our business affairs and management, particularly in key areas like governance, strategic planning, risk management, succession planning and corporate disclosure. These duties are described in our terms of reference for the Board and the Board Committees. They are drafted by management under the guidance of the Governance Committee and approved by the Board, which reviews them once a year and updates them as needed.

The Board is responsible for developing position descriptions for the Chair of the Board and each committee chair. These descriptions are part of their terms of reference and are reviewed annually. The Board has also developed terms of reference for the President & Chief Executive Officer. The Governance Committee defines the division of duties between the Board and our Chief Executive Officer.

You can find more information about the responsibilities of our Board in the Canada Business Corporations Act and in the articles and by-laws and terms of reference on our website (www.enbridge.com).

Strategic planning

The Board is responsible for reviewing our strategic planning process and for reviewing and approving our strategic plan. It oversees the implementation of the plan, monitors our progress and approves any transactions it believes will have a significant impact on the plan or our strategic direction.

The Board devotes two meetings a year to the strategic plan, including one meeting that is held over two days.

Risk management

The Board is responsible for overseeing risk and the risk assessment process, including:

•: establishing the risk tolerance;
•: making sure we identify principal risks once a year;
•: ensuring the implementation of appropriate systems to manage risks;
•: monitoring our risk management programs; and
•: seeking assurance that our internal control systems and management information systems are in place and operating effectively.

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Corporate risk assessment

We have a comprehensive risk assessment system that incorporates information from each of our major businesses. This process involves analyzing both existing and emerging risks in defined categories and any factors that might mitigate them. The Board and the Audit, Finance & Risk Committee review our principal business risks every year, monitor our risk management program and work with our internal and external auditors to oversee the risk review process.

Operational Risk Management Plan (ORM Plan)

The Board is responsible for providing direction on our ORM Plan which broadly aims to position us as the industry leader for system integrity, environmental and safety programs, and charts the course for best-in-class practices. Each of the major business units presents their ORM Plan progress to the Board annually and provides interim updates to the Corporate Social Responsibility Committee.

Board Committees' role in risk management

The Board has delegated specific risk management responsibilities to each Board Committee. The Board Committees can authorize the implementation of systems that address risks within the scope of their responsibility and monitor them to ensure they remain effective. For example, the Corporate Social Responsibility Committee authorized our guidelines on the global reporting initiative and our environmental risk management system.

Internal controls

The Board seeks assurance at least annually that our internal control systems and management information systems are operating effectively.

The Board has delegated responsibility for reviewing our quarterly and annual financial statements to the Audit, Finance & Risk Committee, which recommends them to the Board for approval. The committee is also responsible for overseeing our internal audit function and senior management reporting on internal controls.

Corporate communications

The Board approves all major corporate communications policies, including our corporate disclosure guidelines, which it reviews and approves annually. It also reviews and approves all corporate disclosure documents, including our:

• annual and quarterly reports to shareholders;
• MD&A;

• annual information form; and
• management information circular.

The Board works to ensure we communicate effectively with shareholders, the public and other stakeholders to avoid selective disclosure.

Succession planning

The Board is responsible for:

•: appointing the Chief Executive Officer and other members of senior management;
•: monitoring senior management's performance; and
•: reviewing the succession strategy for all senior management positions every year.

It delegates responsibility for reviewing our policies and procedures relating to employment, succession planning and compensation (including executive compensation) to the Human Resources & Compensation Committee.

The Human Resources & Compensation Committee is also responsible for:

•: making sure we have appropriate programs for dealing with succession planning and employee retention;
•: monitoring the performance of senior management;
•: overseeing human capital risk to make sure our management programs (including those for our officers) effectively address succession planning and employee retention;
•: overseeing the design of our compensation programs from a risk perspective; and
•: reporting to the Board on organizational structure and succession planning matters.

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OUR EXPECTATIONS OF OUR DIRECTORS

Our directors are expected to act in the best interests of Enbridge. They have a duty of care to exercise in both decision making and oversight.

Independence

First and foremost, we believe in the importance of an independent board. The Governance Committee is responsible for making sure the Board functions independently of management.

The majority of our directors must be independent, as defined by Canadian securities regulators in NI 52-110, NYSE rules and the rules and regulations of the US Securities and Exchange Commission.

We define a director as independent if he or she does not have a direct or indirect material relationship with Enbridge. The Board believes that a relationship is material if it could reasonably interfere with a director's ability to make independent decisions, regardless of any other association he or she may have. The Board uses a detailed questionnaire to determine if a director is independent.

Eleven of our 12 nominated directors, including the Chair of the Board, are independent. Mr. Monaco is not independent because he is our President & Chief Executive Officer and a member of management.

The Governance Committee has developed guidelines to give directors a clear picture of the Board's expectations. Key expectations include meeting attendance, financial literacy and ethical conduct.

Separate chair and chief executive officer positions

We have an independent, non-executive Chair of the Board who is responsible for leading the Board.

Meeting in camera

Our terms of reference stipulate that the Board must hold in-camera meetings regularly, without officers or management present. Both the Board and Board Committees meet in camera and independently of management at every regularly scheduled meeting. The Chair of the Board provides the Chief Executive Officer with a summary of the matters discussed at these in-camera meetings, including any issues that the Board expects management to pursue.

Other directorships

Our directors may serve on the boards of other public companies and together on the boards and committees of other public entities, as long as their common memberships do not affect their ability to exercise independent judgment while serving on our Board. See Interlocking relationships on page 18 for information about some of our directors who serve together on other boards.

Directors who serve on our Audit, Finance & Risk Committee cannot sit on the audit committees of more than two other public entities unless they receive approval from our Board. In 2009, the Board approved Mr. Leslie serving on the audit committees of four publicly traded companies, including Enbridge. Since Mr. Leslie is no longer employed full-time, the Board believes he has the time to meet these commitments and his work on the boards and audit committees of these companies is very valuable to him and the Board in his role as chair of our Audit, Finance & Risk Committee. Mr. Leslie continues to serve on the audit committees of the three other publicly traded companies.

External consultants and other third parties

To make sure the Board functions independently of management, Board Committees have the flexibility to meet with external consultants and Enbridge employees without management whenever they see fit. The terms of reference also allow individual directors, the Board and Board Committees to hire independent advisors, as needed.

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Attendance

We expect directors to attend all Board and Board Committee meetings of which they are a member and the annual meeting of shareholders. The Governance Committee reviews each director's attendance record every year. If a director has a poor attendance record, the committee chair and Chair of the Board will discuss and recommend how to handle the matter. A director whose attendance record continues to be poor may be asked to leave the Board. In 2012, the overall attendance at Board and Committee meetings was 99%. Please see information on attendance in the Director Profiles beginning on page 8.

Financial literacy

The Board defines an individual as financially literate if he or she can read and understand financial statements that are generally comparable to ours in breadth and complexity of issues. The Board has determined that all of the members of the Audit, Finance & Risk Committee are financially literate according to the meaning of NI 52-110 and the rules of the NYSE. It has also determined that Mr. England, Mr. Leslie and Ms. Williams each qualify as "audit committee financial experts" as defined by the US Securities Exchange Act of 1934. The Board bases this determination on each director's education, skills and experience.

Orientation and continuing education

The Board recognizes that proper orientation and continuing education are important for directors to fulfill their duties effectively. It has delegated these responsibilities to the Governance Committee, which has developed a comprehensive program for new directors and for directors who join a committee for the first time.

Orientation

Every new director meets with the Chair of the Board, the President & Chief Executive Officer and senior management to learn about our business and operations and participates in tours of our sites and facilities.

New directors are also given a copy of the Board manual, which contains:

•  personal information about each of the directors and senior officers;
•  a list of the members of the Board, the members of the Board Committees and all meeting dates;
•  organizational charts (corporate and management);
•  our financial risk management policies;
•  statutory liabilities;

•  information about the directors' and officers' liability programs;
•  insider trading and indemnity agreements;
•  information about our dividend reinvestment and share purchase plan;
•  our statement on business conduct; and
•  public disclosure documents for our subsidiaries.

Directors are notified by email whenever there are updates to these documents. The manual and any updates are also posted on the Board portal, software that allows directors to securely access board documents online.

Continuing education

We offer education sessions for directors on key topics and encourage them to participate in associations and organizations that can broaden their awareness and knowledge of developments related to our business. Throughout their tenure, directors have discussions with the Chair of the Board, receive quarterly presentations from senior management on strategic issues and participate in tours of our operations. Quarterly briefings include reviews of the competitive environment, our performance relative to our peers and any other developments that could materially affect our business. Directors can also request presentations on a particular topic. See the list of the internal seminars and other presentations we offered in 2012 and director participation on page 17.

We also pay for continuing education opportunities through third parties and we encourage directors to pursue director education seminars and courses offered externally.

A number of our directors are members of Canada's Institute of Corporate Directors (ICD), including Mr. Leslie (chair of the Audit, Finance & Risk Committee), Mr. Shultz (a member of the Audit, Finance & Risk and Human Resources & Compensation Committees) and Ms. Williams (chair of the Human Resources & Compensation Committee). Mr. Leslie is also an active member of the Canadian Audit Committee Network. Ms. Kempston Darkes was recognized by the ICD

2013 Management information circular 26

in 2011 with a Fellowship Award, which the ICD considers to be the highest distinction for directors in Canada. Mr. Shultz will be receiving this Fellowship Award from the ICD at its national conference in May 2013.

BOARD EVALUATION

The Governance Committee is responsible for assessing the performance of the Board and its Chair, the Board Committees and individual directors on an ongoing basis.

Assessing the Board and Chair of the Board

All of the directors complete a confidential questionnaire every year so they can evaluate the effectiveness of the Board and suggest ideas for improving performance. The questionnaire is designed to provide constructive input to improve overall Board performance and includes questions on:

• Board composition;
• effectiveness of the Board, Board meetings and Chair of the Board;

•  duties and responsibilities;
•  Board orientation and development; and
•  the evaluation process for senior management.

In 2011, the evaluation process was revised to include additional questions for directors to evaluate their peers. The directors were asked to consider criteria such as skills and experience, preparation, attendance and availability, communication and interaction with Board members and/or management and business, company and industry knowledge. Directors were encouraged to comment broadly, positively and negatively, on any issue concerning the Board, Board Committees and director performance.

Directors submit their completed questionnaires to the chair of the Governance Committee, who presents the feedback to the Chair of the Board. The chair of the Governance Committee then presents the summary to the Board. The Board discusses the results and develops recommendations as appropriate.

From time to time, the Chair of the Board meets informally with each director, to discuss performance of the Board, Board Committees and other issues.

Board Committee assessments

Each director also completes a confidential questionnaire for each Board Committee of which they are a member. The questionnaire is designed to facilitate candid conversation among the members of each Board Committee about the Board Committee's overall performance, function, areas of accomplishment and areas for improvement. This session takes place in camera at the first Board Committee meeting after the directors complete their questionnaires.

The questionnaire helps the Board ensure each Board Committee is functioning effectively and efficiently and fulfilling its duties and responsibilities as described in its terms of reference. It includes questions about:

• the composition of the Board Committee;
• the effectiveness of the Board Committee and Board Committee meetings;

• committee members, including the chair; and
• the orientation and development processes for the Board Committee.

Completed questionnaires are submitted to the chair of the Governance Committee, who summarizes them and provides a copy to each Board Committee chair and the Chair of the Board.

Identifying new candidates

Directors generally retire from our Board at the age of 73. A director may be asked to remain on the Board for an additional two years if the Board unanimously approves the extension. If a director receives an extension, he or she is not eligible to serve as Chair of the Board or chair of any of the Board's four standing Board Committees.

The Governance Committee serves as the nominating committee and is responsible for identifying new candidates for nomination to the Board. The Governance Committee also invites and welcomes suggestions from other directors on our Board and from management. The committee reviews a Board composition plan annually. The plan consists of a skills matrix that includes the name of each director, his or her occupation, residence, gender, age, years on the Board, retirement date, business experience, other board commitments, equity ownership, independence and other relevant information. The committee summarizes the plan to identify the ideal skills and experience of a new candidate. These

27 ENBRIDGE INC.

include management, board and industry experience, areas of expertise, global representation, gender and age, among others. The committee ranks each of these skills and areas of experience as a high, medium or low priority.

The Governance Committee then develops a list of potential candidates with the desired skills and experience and reviews and updates the list at least once a year. When a position becomes available, the Board reviews the list of potential candidates, revises it to reflect the skills and experience most needed at the time, adds other recently identified candidates and prepares a short list. The committee also considers the candidate's background and diversity of experience in making their choices.

The chair of the Governance Committee, the Chair of the Board, the President & Chief Executive Officer and sometimes other directors, meet with potential candidates to determine their interest, availability, experience and suitability. The Governance Committee makes a recommendation to the Board. The Board discusses the recommendation and decides which candidates will be put forward for election at the annual meeting of shareholders.

About diversity

We are committed to increasing the diversity of our Board over time by actively seeking qualified candidates who meet diversity criteria. Enbridge is one of over 40 founding members of the Canadian Board Diversity Council.

BOARD COMMITTEES

Our Board has four standing Board Committees to help it carry out its duties and responsibilities:

• Audit, Finance & Risk;
• Corporate Social Responsibility;

• Governance; and
• Human Resources & Compensation.

The Board has delegated certain responsibilities to each Board Committee, including overseeing risk management systems that are within the scope of the responsibilities of each Board Committee. Each Board Committee is made up entirely of independent directors. Mr. Monaco, our President & Chief Executive Officer, is not a member of any Board Committee.

Board Committee meetings generally take place before each regularly scheduled Board meeting. Each Board Committee also meets in camera, independent of management, following the regular Board Committee meeting. They also meet with external consultants and/or Enbridge staff, without management present, whenever they see fit.

Each Board Committee reports regularly to the Board and makes recommendations on certain matters as appropriate. The Governance Committee is responsible for recommending the role of each Board Committee to the Board.

Audit, Finance & Risk Committee

Chair:		David Leslie
Members:		Herb England, Charlie Fischer, George Petty, Chuck Shultz and Cathy Williams

The Audit, Finance & Risk Committee assists the Board in overseeing:

•: the integrity of our financial statements and financial reporting process;
•: the integrity of our management information systems, disclosure controls, financial controls and internal audit function;
•: our external auditors, PwC, and ensuring they maintain their independence; and
•: our compliance with financial and accounting regulatory requirements and our risk management program.

The Audit, Finance & Risk Committee is responsible for ensuring the committee, our external auditors, our internal auditors and management of Enbridge maintain open communications.

The Audit, Finance & Risk Committee is responsible for:

Financial reporting

•: reviewing our quarterly and annual MD&A, financial statements and notes and recommending them to the Board for approval;
•: reviewing and approving earnings releases and recommending them to the Board for approval;

2013 Management information circular 28

•: discussing with management and the external auditors any significant issues regarding our financial statements and accounting policies;
•: reviewing with management any anticipated changes in reporting standards and accounting policies;

Internal controls

•: overseeing management's system of disclosure controls and procedures;
•: overseeing the internal controls over financial reporting;
•: overseeing the internal audit function;

External auditors

•: reviewing the qualifications and independence of our external auditors, PwC, and recommending their appointment to the Board;
•: reviewing all audit and non-audit services to be provided by the external auditors, including proposed fees, and pre-approving them, consistent with our policy; and
•: setting the compensation of the external auditors, reviewing their performance, overseeing their activities and retaining them in their role as external auditors.

The external auditors report directly to the Audit, Finance & Risk Committee. They meet regularly with the committee, in camera, without any members of management present. The chair of the committee also meets with the senior partner of PwC from time to time, to discuss significant issues.

The Audit, Finance & Risk Committee is also responsible for:

Finance

•: reviewing the issue of securities by Enbridge and authorizing or recommending such matters to the Board for approval;
•: overseeing the filing of prospectuses or related documents with securities regulatory authorities; and
•: overseeing credit facilities and inter-company financing transactions and recommending them to the Board for approval.

Risk management

•: overseeing the annual review of Enbridge's principal risks;
•: reviewing risks in conjunction with internal and external auditors;
•: monitoring our risk management program; and
•: reviewing our annual report on insurance coverages.

Together with the Board, the committee also reviews with senior management, internal counsel and others as necessary:

•: our method of reviewing risk and our strategies and practices related to assessing, managing, preventing and mitigating risk; and
•: loss prevention policies, risk management programs and disaster response and recovery programs.

2012 highlights

The Audit, Finance & Risk Committee carried out the following activities during 2012:

Audits and financial reporting

•: reviewed the interim and annual MD&A and financial statements and notes and recommended them to the Board for approval;
•: reviewed public disclosure documents containing audited or unaudited financial information, including annual and interim earnings press releases, prospectuses and the annual information form, and recommended them to the Board for approval for public release;
•: reviewed and approved the pension plan annual financial statements;
•: the chair of the Audit, Finance & Risk Committee reviewed and approved the prior year's expenses of the President & Chief Executive Officer;

29 ENBRIDGE INC.

Internal controls

•: reviewed the quarterly internal controls compliance reports;
•: reviewed the audit services role and audit plan and received quarterly audit services reports;
•: reviewed the audit services annual report;
•: received quarterly updates on the ethics and conduct hotline activity from the Chief Compliance Officer;

External auditors

•: carried out an assessment of PwC, recommended its appointment by shareholders and reviewed and approved the 2012 engagement letter (including the terms of engagement and proposed fees);
•: approved a revised policy regarding hiring employees from the external auditor;
•: pre-approved all non-audit services to be provided by PwC that are allowed under the committee's policy;

Finance

•: reviewed quarterly treasury management reports;
•: reviewed the financing plans including additional financing transactions not included in the 2012 annual financing plan, credit facilities and inter-company financing transactions, and recommended them to the Board for approval;

Risk management

•: reviewed the quarterly financial risk management reports;
•: reviewed and approved the 2012 corporate risk assessment report;
•: received information on insurance recoveries from 2010 and 2011 claims;
•: reviewed the annual report on insurance coverages and reviewed and approved the insurance renewal strategy; and
•: reviewed the information security report.

Governance

In November 2012, the Audit, Finance & Risk Committee reviewed its terms of reference. The committee reviewed the qualifications of its members, and recommended to the Board members who it believes can be properly considered audit committee financial experts. The committee also reviewed its performance in 2012 and determined that it had fulfilled all of its responsibilities under its terms of reference.

The Audit, Finance & Risk Committee met 10 times in 2012. It held in-camera meetings without management present at each of its regularly scheduled meetings with the senior member of the Internal Audit group as well as with the external auditors and then it met on its own in camera. The Committee spent a considerable amount of time in early 2012 on an investigation of some issues in the subsidiary of one of our sponsored investments, which resulted in an unfavourable prior period adjustment in relation to a natural gas liquids trucking and marketing business. Another area of focus in 2012 was the committee's work related to the effectiveness of strategies to mitigate commodity price risk. From time to time the committee also met in camera with the Chief Financial Officer. Before each meeting, the chair of the committee met with the Chief Financial Officer to discuss the agenda items for the meeting and any significant issues. The chair also met with the senior partner of the external auditors assigned to Enbridge's audit before each meeting. You can find more information about the committee as required under NI 52-110 under Audit, Finance & Risk Committee in our annual information form for the year ended December 31, 2012. Copies are available on our website (www.enbridge.com) and on SEDAR (www.sedar.com). You can also request a copy from the corporate secretary.

Corporate Social Responsibility Committee

Chair:		James Blanchard
Members:		Maureen Kempston Darkes, George Petty and Dan Tutcher

The Corporate Social Responsibility Committee is responsible for assessing our guidelines, policies, procedures and performance related to corporate social responsibility (CSR) and reviewing our reporting in this area.

Assessing CSR guidelines, policies and procedures

The Corporate Social Responsibility Committee is responsible for:

•: reviewing, approving or recommending to the Board the risk guidelines, policies, procedures and practices relating to CSR matters and approving them or recommending them to the Board for approval. CSR matters include the

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environment, health and safety, human rights, aboriginal relations, stakeholder relations, community investment, government affairs, injury – prevention and emergency response matters;

•: reviewing and approving our CSR metrics and benchmarks;
•: reviewing and approving our methods of communicating CSR and related policies;

Monitoring and reporting CSR performance

•: monitoring our performance on CSR matters and receiving regular compliance reports from management;
•: reviewing the results of investigations into significant accidents or environmental incidents; and
•: reporting related to our CSR performance.

The Corporate Social Responsibility Committee has approved the use of the Global Reporting Initiative (GRI) reporting guidelines for monitoring and reporting our sustainability performance.

2012 highlights

The Corporate Social Responsibility Committee carried out the following activities as part of its 2012 work plan:

Assessing CSR guidelines, policies and procedures

•: received updates on CSR developments (including the environment, health and safety);
•: received management's reports on:
•: pipeline security, corporate security and information security; and
•: public health emergency planning;
•: discussed our energy4everyone foundation, a foundation created in 2009 to work towards reducing poverty by delivering affordable, reliable and sustainable energy to communities in need;

Reviewing our work with stakeholders

•: received management's update on the work of the Aboriginal and Stakeholder Relations group;
•: received management's quarterly updates on our work with governments, regulators and the communities in which we conduct business;
•: received updates on Northern Gateway including community consultation, Aboriginal engagement, the regulatory process and other matters;
•: facilitated a meeting of the committee and the Board of Directors with representatives of the proponents of a shareholder proposal submitted at the 2012 annual meeting of shareholders, to discuss issues relating to Northern Gateway;
•: reviewed progress on Enbridge's neutral footprint strategy;
•: received reports on community investments, including donations to charitable organizations;

Monitoring and reporting CSR performance

•: reviewed the 2012 environment, health & safety reports by the Gas Transportation, Liquids Pipelines, Major Projects and Gas Distribution business units;
•: received information on work planned for 2012 and 2013 to respond to proposed environmental legislation in Canada and the US;
•: reviewed pipeline integrity issues;
•: undertook, at the request of the Board, an update of the business units' work on operations risk management issues, including mitigation work on their principal operating risks;
•: received presentations and reports on the July 2010 oil spill near Marshall, Michigan, the September 2010 oil spill near Romeoville, Illinois and on the community, government relations and pipeline safety and integrity work we have completed and are continuing to work on, following those incidents; and
•: reviewed our 2012 CSR report, which was prepared using the GRI G3 sustainability reporting guidelines. The GRI guidelines serve as a framework for reporting on an organization's economic, environmental and social performance.

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Awards and recognition

The Corporate Social Responsibility Committee supports our continuing commitment to CSR initiatives, which has resulted in Enbridge receiving significant positive recognition in recent years, including the following awards in 2012:

•: Corporate Knights Best 50 Corporate Citizens in Canada;
•: Corporate Knights Global 100 list of the Most Sustainable Corporations;
•: Mediacorp Canada's list of Alberta's Top 50 Employers;
•: Mediacorp Canada's list of Canada's Greenest Employers;
•: Mediacorp Canada's list of Canada's Top 100 Employers;
•: Medicorp Canada's list of Canada's Top Employers for Young People; and
•: Dow Jones Sustainability World and North America Indexes.

Governance

In November 2012, the committee reviewed its terms of reference and determined that it had fulfilled all of its responsibilities under its terms of reference.

The Corporate Social Responsibility Committee met four times in 2012 and held in-camera meetings without management present at the end of each meeting.

Governance Committee

Chair:		Dan Tutcher
Members:		James Blanchard, Lorne Braithwaite and David Leslie

The Governance Committee focuses on ensuring we have a comprehensive system of stewardship and accountability for directors, management and employees that is in the best interests of shareholders.

The Governance Committee is responsible for developing our approach to governance, including the division of duties between the Chair of the Board, directors, the President & Chief Executive Officer and management.

It is responsible for:

•: recommending matters about overall governance to the Board;
•: reviewing the terms of reference for the Board and the Board Committees;
•: setting corporate governance guidelines for the Board; and
•: reviewing management's compliance reports on corporate governance policies.

The Governance Committee works closely with the Corporate Secretary and other members of management to keep abreast of governance trends and implement board governance best practices.

Board composition, education and evaluation

The Governance Committee is responsible for:

•: developing a Board composition plan and recommending the nomination of directors to the Board and Board Committees;
•: establishing formal orientation and education programs for directors;
•: reviewing and reporting to the Board on risk management matters relating to corporate liability protection programs for directors and officers;
•: assessing the performance of the Board, Board Committees, the Chair of the Board and individual directors;
•: monitoring the quality of the relationship among Board members and Board Committees and with management and recommending any changes; and
•: ensuring the Board functions independently of management.

One of the Governance Committee's objectives is to nominate a balanced mix of members to the Board who have the necessary experience and expertise to make a meaningful contribution in carrying out duties on behalf of the Board. It sets guidelines for recruiting new talent with criteria for relevant expertise, senior management experience or other qualifications, recognizing our diversity goal of having more women and visible minorities on our Board.

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The Governance Committee manages the annual performance review of the Board. See Board evaluation on page 27 for more information.

Compensation

The Governance Committee is responsible for reviewing and setting directors' compensation. An increase in directors' compensation was approved January 1, 2010 and an increase in the Chair's compensation was approved effective January 1, 2012. See Directors – Compensation discussion and analysis on page 36 for more information.

2012 highlights

The Governance Committee carried out the following activities as part of its 2012 work plan:

•: reviewed shareholder proposals, proxy voting recommendations and annual meeting voting results for the 2012 meeting;
•: approved our statement on corporate governance practices for this circular;
•: reviewed how shareholder engagement and "say on pay" have evolved and agreed to recommend that Enbridge hold a third advisory vote on our approach to executive compensation, at the 2013 shareholders' meeting;
•: received reports on employee and director compliance with the statement on business conduct;
•: reviewed the qualifications and independence of all members of the Board;
•: reviewed management's reports on our director and officer liability protection program and management information systems;

Board composition and evaluation

•: reviewed the Board composition plan and skills matrix for the current Board and analyzed the implications our strategic plan has on Board composition;
•: recommended changes in the composition of the Committees, to allow for new contributors to those committees; and
•: conducted the Board evaluation process for 2012 and reviewed and reported to the Board on the results of the various assessments.

Governance

The Governance Committee reviewed its performance in 2012 and determined that its mandate was appropriate and that the committee had fulfilled all of its responsibilities under its terms of reference.

The Governance Committee met four times in 2012 and held in-camera meetings without management present at the end of each meeting.

Human Resources & Compensation Committee

Chair:		Cathy Williams
Members:		Lorne Braithwaite, Herb England, Charlie Fischer, Maureen Kempston Darkes and Chuck Shultz

The Human Resources & Compensation Committee assists the Board by providing oversight and direction on human resources strategy, policies and programs for the named executives (as defined on page 41 of this circular), senior management and our broader employee base. This includes compensation, pension and benefits as well as talent management, succession planning, workforce recruitment and retention. The Human Resources & Compensation Committee is also responsible for overseeing the company's compensation programs from a risk perspective to ensure they do not encourage individuals to take inappropriate or excessive risks that are reasonably likely to have a material adverse effect on the company.

Succession planning

The Human Resources & Compensation Committee reviews the succession plan for the position of Chief Executive Officer and other key senior officers, and long-range planning for executive development and succession to ensure leadership sustainability and continuity.

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Every year the Human Resources & Compensation Committee conducts a thorough review of the current succession plan and the status of development and retention plans for candidates who have been identified for senior executive positions, including the position of Chief Executive Officer.

Chief Executive Officer succession has been a significant focus for the Human Resources & Compensation Committee and the Board over the past two years. Having indicated his intent to retire sometime in 2012, Mr. Daniel, as President & Chief Executive Officer, met several times with members of the Human Resources & Compensation Committee, without other members of management, to discuss the transition plan for his successor, then continued to meet with them throughout the transition period to review progress. Later in the year, the Human Resources & Compensation Committee met with the incoming President & Chief Executive Officer, Mr. Monaco, to discuss his views on the executive leadership team and potential succession approaches. The Human Resources & Compensation Committee also met in camera, without Mr. Monaco, to discuss the candidates he had identified as his possible successors.

Given the potential retirement eligibility within the Executive Leadership Team, executive succession and candidate development and retention will continue to be an area of focus for the Human Resources & Compensation Committee and the Board in 2013.

2012 highlights

The Human Resources & Compensation Committee:

•: worked with the Chair of the Board to finalize the succession plan for the position of President & Chief Executive Officer, considered Mr. Daniel's retirement in 2012, determined the appropriate transition plan, monitored its progress and recommended staged compensation for Mr. Monaco as incoming successor to recognize his appointment to President and then President & Chief Executive Officer;
•: was asked, on behalf of the Board, to negotiate Mr. Monaco's terms of employment, as the incoming President & Chief Executive Officer. The Human Resources & Compensation Committee retained external advisors (both executive compensation and legal) to assist in this matter and a new executive employment agreement for Mr. Monaco was signed on February 12, 2013, effective October 1, 2012;
•: reviewed both company and business unit performance, based on the approved short-term incentive performance metrics and corporate financial performance compared to our peers and the TSX60 and TSX Composite Index over several time periods, and used these assessments to determine 2012 short-term, medium-term and long-term incentive awards for our executives and employees;
•: evaluated Mr. Daniel's (while in the position of Chief Executive Officer) performance and recommended all aspects of his compensation for 2012 to the Board, including his base salary and short-term, medium-term and long-term incentive awards;
•: reviewed a competitive analysis and Mr. Monaco's performance assessments and compensation recommendations for the other executive officers, including recommendations for their base salaries and short-term, medium-term and long-term incentive awards for 2012;
•: reviewed and approved the design of the 2012 Performance Stock Option Plan and approved the grant for 2012 – 2016;
•: reviewed and approved changes to the peer group utilized for executive compensation benchmarking purposes;
•: reviewed and approved the Compliance and Monitoring Report as part of the pension governance process, including the funding status;
•: approved the annual general salary increase recommendations;
•: approved several administrative amendments to the Canadian and US pension plans to align with changes in regulatory wording;
•: reviewed and approved revisions to the company's Statement of Investment Policies and Procedures based on the results of an Asset Liability Study;
•: reviewed the succession plans for senior executive roles, discussed development and retention planning for key successors and requested regular progress updates on development plan execution;
•: recommended officer appointments to the Board for ratification; and
•: considered compensation risk in the approval of compensation programs, measures and targets.

2013 Management information circular 34

The Human Resources & Compensation Committee also reviewed the strategies and programs designed to attract, develop and retain employees, recognizing our plans for significant growth and increasing levels of retirement eligibility.

Awards and recognition

Enbridge was recognized in 2012 as one of Canada's Top 100 Employers, a Top Employer for Canadians Over 40 and one of Alberta's Top Employers. Enbridge was also named one of Canada's Greenest Employers.

Governance

In November 2012, the Human Resources & Compensation Committee reviewed its mandate, as set out in its terms of reference, and its performance. The members of the committee are satisfied that the mandate is appropriate and that it met its responsibilities in 2012. The Committee made several clarifying additions to its terms of reference to more fully reflect the Committee's full range of responsibilities.

The Human Resources & Compensation Committee met six times in 2012, and held an in camera meeting, without management present, at the end of each meeting.

35 ENBRIDGE INC.

3. Compensation

This next section discusses director and executive compensation at Enbridge, including our decision-making process, pay for performance, share ownership requirements and 2012 pay decisions.

DIRECTORS

COMPENSATION DISCUSSION AND ANALYSIS

Philosophy and approach

The Board is responsible for developing and implementing the directors' compensation plan and has delegated the day-to-day responsibility for director compensation to the Governance Committee.

Our directors' compensation plan is designed with four key objectives in mind:

•: to attract and retain the most qualified individuals to serve as directors;
•: to compensate our directors to reflect the risks and responsibilities they assume when serving on our Board and Board Committees;
•: to offer directors compensation that is competitive with other public companies that are comparable to Enbridge; and
•: to align the interests of directors with those of our shareholders.

While our executive compensation program is designed around pay for performance, director compensation is based on annual retainers. This is to meet the compensation objectives and to help ensure our directors are unbiased when making decisions and carrying out their duties while serving on our Board.

The Governance Committee uses a peer group of companies to set the annual retainers for our Board and targets director compensation at about the 75^th percentile. It uses the same peer group, as much as possible, to determine executive compensation. See page 46 for more information about our peer group and how we benchmark executive compensation.

The Governance Committee reviews the compensation plan every year and works with external consultants as needed. As part of this review, the committee considers the time commitment and experience required of members of our Board and the director compensation paid by a group of comparable public companies when it sets the compensation. The committee also reviews the compensation plan to make sure the overall program is still appropriate and reports its findings to the Board.

Share ownership

We expect directors to own Enbridge shares so they have an ongoing stake in the company and are aligned with the interests of shareholders. The ownership guideline changed from two times to three times the annual Board retainer effective January 1, 2013. Directors must now hold at least three times their annual Board retainer, or $630,000, in DSUs or Enbridge shares and meet that requirement within five years of becoming a director on our Board. DSUs are paid out when a director retires from the Board. They are redeemed for cash, based on the weighted average of the closing price of common shares on the TSX for the last five trading days before the redemption date, multiplied by the number of DSUs the director holds.

If a decrease in the market value of our common shares results in a director no longer meeting the share ownership requirements, we expect him or her to buy additional common shares in order to satisfy the minimum threshold.

About DSUs

A deferred share unit (DSU) is a notional share that has the same value as one Enbridge common share. Its value fluctuates with variations in the market price of Enbridge shares.

DSUs do not having voting rights but they accrue dividends as additional DSUs, at the same rate as dividends paid on our common shares.

2013 Management information circular 36

Components

Our Directors' compensation plan has four components:

•: an annual retainer;
•: an annual fee if he or she serves as the non-executive Chair of the Board or chair of a Board Committee;
•: a travel fee for attending Board and Board Committee meetings; and
•: reimbursement for reasonable travel and other out-of-pocket expenses relating to his or her duties as a director.

We do not have meeting attendance fees.

This plan has been in effect since 2004 and was revised in January 2010 when the Board approved an increase in the annual retainer. The Chair's retainer was increased by $20,000 effective January 1, 2012. The table below shows the fee schedule for directors in 2012. Directors are paid quarterly. If their principal residence is in the US, they receive the same face amounts in US dollars. Mr. Monaco joined the Board on February 27, 2012. He does not receive any director compensation because he is our President & Chief Executive Officer and is compensated in that role. Mr. Patrick Daniel, the previous President & Chief Executive Officer, also did not receive directors' fees.

Directors who also serve as a director or trustee of one of our subsidiaries or affiliates also receive an annual retainer and meeting and travel fees for attending those meetings.

Directors can receive their retainer in a combination of cash, Enbridge shares and DSUs, but they must receive a minimum amount in DSUs, as shown in the table below. Travel fees are always paid in cash.



	Annual amount ($)	Cash	Enbridge shares	DSUs	Cash	Enbridge shares	DSUs

Compensation component		before minimum share ownership			after minimum share ownership

Board retainer	210,000

Additional retainers
Chair of the Board retainer	260,000
Board Committee chair retainer		Up to 50%	Up to 50%	50% to 100%	Up to 75%	Up to 75%	25% to 100%
– Audit, Finance & Risk	25,000
– Corporate Social Responsibility	10,000
– Governance	10,000
– Human Resources & Compensation	15,000

Travel fee	1,500	100%	–	–	100%	–	–

Once they reach the minimum share ownership level, directors can choose to receive between one quarter and all of their retainer in DSUs, with the balance in cash, Enbridge shares or a combination of both, according to a percentage mix they choose. They must take at least 25% of the retainer in DSUs. Directors are allocated the Enbridge shares based on the weighted average of the closing price of the Enbridge shares on the TSX for the five trading days immediately preceding the date that is two weeks prior to the date of payment.

The table below shows the breakdown of each director's annual retainer for the year ended December 31, 2012.


	Director	Cash (%)	Enbridge shares (%)	DSUs (%)

David A. Arledge		75	–	25
James J. Blanchard		50	–	50
J. Lorne Braithwaite		50	25	25
Patrick D. Daniel1		–	–	–

37 ENBRIDGE INC.

J. Herb England	50	–	50
Charles W. Fischer	50	–	50
V. Maureen Kempston Darkes	25	50	25
David A. Leslie	–	–	100
Al Monaco2	–	–	–

George K. Petty	75	–	25
Charles E. Shultz	25	50	25
Dan C. Tutcher	–	–	100
Catherine L. Williams	–	50	50

1: Mr. Daniel retired as Chief Executive Officer and from the Board effective September 30, 2012. He did not receive any compensation as a director of Enbridge because he was our Chief Executive Officer.
2: Mr. Monaco joined the Board on February 27, 2012 when he became President of Enbridge. He does not receive any compensation as a director of Enbridge because he is our President & Chief Executive Officer.

2012 RESULTS

Summary compensation table

The table below shows the total compensation paid to or accrued by our directors for the year ended December 31, 2011. All Enbridge shares and DSUs vested at the time of the grant.



			Share-based awards2				All other compensation

		Fees earned1	Enbridge shares3,4		DSUs4		Subsidiary fees5	Travel fees	Dividends on DSUs6		Total
	Director1	(cash) ($)	(#)	($)	(#)	($)	($)	($)	(#)	($)	($)

David A. Arledge7 James J. Blanchard7		352,500 105,000	– –	– –	2,961 2,898	117,500 115,000	– –	9,000 9,000	33 33	1,284 1,256	480,284 230,256

J. Lorne Braithwaite Patrick D. Daniel8		105,091 –	1,330 –	52,409 –	1,332 –	52,500 –	23,000 –	11,000 –	15 –	577 –	244,577 –

J. Herb England7 Charles W. Fischer		105,000 105,000	– –	– –	2,646 2,665	105,000 105,000	153,831 61,250	21,000 6,000	30 30	1,147 1,155	385,978 278,405

V. Maureen Kempston Darkes		52,601	2,662	104,899	1,332	52,500	–	9,000	15	577	219,577

David A. Leslie Al Monaco9		– –	– –	– –	5,964 –	235,000 –	26,000 –	11,000 –	67 –	2,585 –	274,585 –

George K. Petty7		157,500	–	–	1,347	53,438	–	10,500	15	592	222,030
Charles E. Shultz		52,601	2,662	104,899	1,332	52,500	6,750	9,000	15	577	226,327

Dan C. Tutcher7		–	–	–	5,448	216,250	–	9,000	60	2,330	227,580

Catherine L. Williams		75	2,853	112,425	2,855	112,500	6,750	4,500	32	1,237	237,487

1: The cash portion of the retainers paid to the directors.
2: The portion of the retainer received as DSUs and Enbridge shares.
3: Directors may also receive additional Enbridge shares as part of our Dividend Reinvestment and Share Purchase Plan, which is available to all shareholders.
4: We pay directors quarterly. The value of the Enbridge shares and DSUs is based on the weighted average of the closing price of Enbridge shares on the TSX for the five trading days immediately preceding the grant date each quarter. The weighted average Enbridge share prices were $38.47, $39.24, $38.39 and $41.70 for the first, second, third and fourth quarters of 2012.
5: Includes the annual retainers paid to each of Ms. Williams and Messrs. Braithwaite, England, Fischer, Leslie and Shultz as a director or trustee of an Enbridge subsidiary or affiliate, and fees for attending those meetings.
6: Includes dividend equivalents granted in 2012 on DSUs granted in 2012 based on the 2012 quarterly dividend rate of $0.2825. Dividend equivalents vest at the time of grant.
7: These directors are paid the same face amounts in US$ because their principal residence is in the US.
8: Mr. Daniel retired as Chief Executive Officer and from the Board effective September 30, 2012. He did not receive any compensation as a director of Enbridge because he was our Chief Executive Officer.
9: Mr. Monaco joined the Board on February 27, 2012 when he became President of Enbridge. He does not receive any compensation as a director of Enbridge because he is our President & Chief Executive Officer.

Incentive plans awards

We have not granted stock options (stock options or options) to directors since 2002. None of our non-employee directors hold any share-based awards that have not vested.

2013 Management information circular 38

Share-based compensation

The table below shows the breakdown in share-based compensation each director received each quarter in 2012.



		Q1			Q2			Q3			Q4

	Director	Enbridge Shares1	DSUs1	Dividends on 2012 DSUs1	Enbridge Shares1	DSUs1	Dividends on 2012 DSUs1	Enbridge Shares1	DSUs1	Dividends on 2012 DSUs1	Enbridge Shares1	DSUs1	Dividends on 2012 DSUs1

David A. Arledge2		–	$29,122	–	–	$30,092	$214	–	$28,523	$432	–	$28,964	$645
			(757 units)			(757 units/5 units)			(743 units/11 units)			(695 units/17 units)

James J. Blanchard2		–	$28,503	–	–	$29,452	$209	–	$27,916	$423	–	$28,348	$631
			(740 units)			(751 units/5 units)			(727 units/11 units)			(680 units/16 units)

J. Lorne Braithwaite		$13,118	$13,125	–	$13,106	$13,125	$96	$13,091	$13,125	$192	$13,094	$13,125	$290
		(341 Enbridge shares)	(341 units)		(334 Enbridge shares)	(334 units/2 units)		(341 Enbridge shares)	(342 units/5 units)		(314 Enbridge shares)	(315 units/7 units)

Patrick D. Daniel3		–	–	–	–	–	–	–	–	–	–	–	–

J. Herb England2		–	$26,024	–	–	$26,891	$191	–	$25,489	$386	–	$25,883	$576
			(676 units)			(685 units/5 units)			(664 units/10 units)			(620 units/15 units)

Charles W. Fischer		–	$26,250	–	–	$26,250	$193	–	$26,250	$383	–	$26,250	$579
			(682 units)			(669 units/5 units)			(684 units/10 units)			(629 units/15 units)

V. Maureen Kempston Darkes		$26,237	$13,125	–	$26,212	$13,125	$96	$26,220	$13,125	$192	$26,229	$13,125	$290
		(682 Enbridge Shares)	(341 units)		(668 Enbridge Shares)	(334 units/2 units)		(683 Enbridge Shares)	(342 units/5 units)		(629 Enbridge Shares)	(315 units/7 units)

David A. Leslie		–	$58,750	–	–	$58,750	$431	–	$58,750	$857	–	$58,750	$1,296
			(1,527 units)			(1,497 units/10 units)			(1,530 units/22 units)			(1,409 units/33 units)

Al Monaco4		–	–	–	–	–	–	–	–	–	–	–	–

George K. Petty2		–	$13,632	–	–	$13,765	$100	–	$12,744	$200	–	$12,941	$295
			(354 units)			(351 units/2 units)			(332 units/5 units)			(310 units/8 units)

Charles E. Shultz		$26,237	$13,125	–	$26,212	$13,125	$96	$26,220	$13,125	$192	$26,229	$13,125	$290
		(682 Enbridge shares)	(341 units)		(668 Enbridge shares)	(334 units/2 units)		(683 Enbridge shares)	(342 units/5 units)		(629 Enbridge shares)	(315 units/7 units)

Dan C. Tutcher2		–	$52,049	–	–	$55,062	$382	–	$53,405	$781	–	$54,230	$1,180
			(1,353 units)			(1,403 units/10 units)			(1,391 units/20 units)			(1,300 units/30 units)

Catherine L. Williams		$28,122	$28,125	–	$28,096	$28,125	$206	$28,101	$28,125	$410	$28,106	$28,125	$620
		(731 Enbridge shares)	(731 units)		(716 Enbridge shares)	(717 units/5 units)		(732 Enbridge shares)	(733 units/10 units)		(674 Enbridge shares)	(674 units/16 units)

1: Directors are paid in Enbridge shares and DSUs quarterly. Their value is based on the weighted average of the closing price of the Enbridge shares on the TSX for the five trading days immediately preceding the grant date each quarter. DSUs dividends paid in 2012 on DSUs granted in 2012 are valued as of March 1, June 1, September 4 and December 3, 2012. The table below shows the grant dates, dividend dates and the weighted average Enbridge share price for each quarter in 2012.


	Quarter	DSU grant date	Dividend date	Weighted average Enbridge share price for dividend grant	Weighted average Enbridge share price for DSU grant

Q1		March 16, 2012	March 1, 2012	$37.62	$38.47
Q2		June 15, 2012	June 1, 2012	39.88	39.24
Q3		September 14, 2012	September 4, 2012	38.21	38.39
Q4		December 14, 2012	December 3, 2012	38.99	41.70

2: These directors are paid in US$. The amounts they received have been converted to CA$ based on the Bank of Canada noon rate:
March 16, 2012: US$1 = CA$0.9914
June 15, 2012: US$1 = CA$1.0244
September 14, 2012: US$1 = CA$0.9710
December 14, 2012: US$1 = CA$0.986
3: Mr. Daniel retired as Chief Executive Officer and from the Board effective September 30, 2012. He did not receive any compensation as a director of Enbridge because he was our Chief Executive Officer.
4: Mr. Monaco joined the Board on February 27, 2012 when he became President of Enbridge. He does not receive any compensation as a director of Enbridge because he is our President & Chief Executive Officer.

39 ENBRIDGE INC.

Change in equity ownership

The table below shows the change in each director's equity ownership from March 2, 2012 to March 5, 2013 and his or her status in meeting the share ownership requirements. Mr. Daniel is excluded because he retired as Chief Executive Officer and Director effective September 30, 2012.


	Director	Enbridge shares (#)		Enbridge stock options (#)	DSUs (#)	Total Enbridge shares and DSUs (#)		Market (at-risk) value of equity holdings ($)1		Minimum share ownership required2,3 ($)	Current holdings as a multiple of the Board retainer

David A. Arledge
2013		32,600		–	43,511	76,111		3,492,734		630,000	16.63
2012		32,600		–	39,348	71,948		2,754,889		420,000
Change		0		–	4,163	4,163		737,845

James J. Blanchard
2013		10,977		–	94,563	105,540		4,843,231		630,000	23.06
2012		25,770		–	89,016	114,786		4,395,156		420,000
Change		(14,793	)	–	5,547	(9,246	)	448,075

J. Lorne Braithwaite
2013		86,090		–	36,336	122,426		5,618,129		630,000	26.75
2012		84,760		–	33,989	118,749		4,546,899		420,000
Change		1,330		–	2,347	3,677		1,071,230

J. Herb England
2013		2,120		–	43,305	45,425		2,084,553		630,000	9.93
2012		2,120		–	39,460	41,580		1,592,098		420,000
Change		0		–	3,845	3,845		492,455

Charles W. Fischer
2013		8,000		–	12,922	20,922		960,111		630,000	4.57
2012		8,000		–	9,919	17,919		686,119		420,000
Change		0		–	3,003	3,003		273,992

V. Maureen Kempston Darkes
2013		12,705		–	9,682	22,387		1,027,339		630,000	4.89
2012		10,000		–	8,089	18,089		692,628		420,000
Change		2,705		–	1,593	4,298		334,711

David A. Leslie
2013		10,456		–	45,722	56,178		2,578,008		630,000	12.28
2012		10,179		–	38,526	48,705		1,864,914		420,000
Change		277		–	7,196	7,473		713,094

Al Monaco3
2013		118,596		2,458,700	–	118,596		5,442,370		–	–
2012		96,303		1,170,900	–	96,303		3,687,442		–	–
Change		22,293		1,287,800	–	22,293		1,754,928

George K. Petty
2013		1,894		–	50,220	52,114		2,391,511		630,000	11.39
2012		26,594		–	47,464	74,058		2,835,681		420,000
Change		(24,700	)	–	2,756	(21,944	)	(444,170	)

Charles E. Shultz
2013		31,657		–	37,454	69,111		3,171,504		630,000	15.10
2012		28,466		–	35,075	63,541		2,432,985		420,000
Change		3,191		–	2,379	5,570		738,519

Dan C. Tutcher
2013		630,711		–	49,766	680,447		31,227,090		630,000	148.70
2012		616,856		–	42,966	659,822		25,264,584		420,000
Change		13,855		–	6,800	20,655		5,962,506

2013 Management information circular 40


	Director	Enbridge shares (#)	Enbridge stock options (#)	DSUs (#)	Total Enbridge shares and DSUs (#)	Market (at-risk) value of equity holdings ($)1	Minimum share ownership required2,3 ($)	Current holdings as a multiple of the Board retainer

Catherine L. Williams
2013		28,841	–	22,066	50,907	2,336,122	630,000	11.12
2012		25,394	–	18,616	44,010	1,685,143	420,000
Change		3,447	–	3,450	6,897	650,979

Total
2013		974,647	2,458,700	445,547	1,420,194	65,172,703
2012		967,042	1,170,900	402,468	1,369,510	52,438,538
Change		7,605	1,287,800	43,079	50,684	12,734,165

1: Based on the total market value of Enbridge shares and/or DSUs owned by the director, based on the closing price of $38.29 on the TSX on March 2, 2012 and $45.89 on March 5, 2013. These amounts have been rounded to the nearest dollar. Excludes stock options.
2: Each Director met the share ownership guideline by or before the applicable deadline and now exceeds that share ownership guideline. The ownership guideline changed from two times to three times the Board retainer effective January 1, 2013. The Board retainer is $210,000.
3: Mr. Monaco joined the Board on February 27, 2012. He does not receive any compensation as a director of Enbridge. He is only compensated for his role as President & Chief Executive Officer. He is required to hold at least five times his base salary in Enbridge shares. Please see page 47 of this circular for information on his Enbridge share ownership as a multiple of his base salary.

EXECUTIVES

COMPENSATION DISCUSSION AND ANALYSIS

Named executive officers

For 2012, the Enbridge named executives include the following individuals:

•: Patrick D. Daniel, former President & Chief Executive Officer;
•: Al Monaco, current President & Chief Executive Officer;
•: J. Richard Bird, Executive Vice President, Chief Financial Officer & Corporate Development;
•: Stephen J. Wuori, President, Liquids Pipelines & Major Projects;
•: David T. Robottom, Executive Vice President & Chief Legal Officer; and
•: Janet A. Holder, Executive Vice President, Western Access.

Executive summary

Key developments in 2012

Chief Executive Officer succession has been a significant focus for the Human Resources and Compensation Committee (HRC Committee) and the Board over the past two years, including a review of potential internal and external succession candidates. In February 2012, Mr. Daniel, as President & Chief Executive Officer, provided formal notice to the Board of Directors of his intention to retire on or before the end of 2012. The Board of Directors, in consultation with the chair of the HRC Committee, confirmed previous discussions on succession plans and candidates which resulted in the appointment of Mr. Monaco to President of Enbridge and a member of the Board of Directors effective February 27, 2012. After working with Mr. Daniel to determine an appropriate transition plan, the HRC Committee continued to meet throughout the transition period to monitor progress. Mr. Daniel retired effective September 30, 2012. The Board of Directors appointed Mr. Monaco to President & Chief Executive Officer effective October 1, 2012.

As part of the transition plan, Enbridge expanded the portfolios of responsibilities of Messrs. Bird and Wuori, with each taking on some of the responsibilities previously held by Mr. Monaco.

Performance highlights for 2012

The following summarizes some our key accomplishments in 2012:

•: reinforced safety and operational integrity through a comprehensive operational risk management assessment and planning initiative;

41 ENBRIDGE INC.

•: achieved strong earnings and cash flow growth with adjusted earnings per share (EPS) rising 11%;
•: increased our quarterly dividend by 12% effective March 1, 2013;
•: generated total shareholder return for 2012 of 16.2%;
•: added a total of $14 billion to our portfolio of commercially secured growth projects;
•: reached a 52-week trading high of $43.05 on the TSX on December 31st, and closed the year at $43.02; and
•: received recognition for corporate social responsibility and sustainability practices, including being named one of Canada's Greenest Employers and a Top 100 Employer.

Pay for performance

In making decisions on performance-based compensation in 2012, the HRC Committee considered the strong financial growth the company achieved and the notable operational successes across the business units. In addition, the HRC Committee considered Enbridge's significant outperformance over our competitors on other key performance indicators such as dividend per share growth, reward to risk ratio and total shareholder return. Taking into account these circumstances, total annual cash compensation increased by 3% for the named executives of 2012 versus the named executive officers of last year (the 3% increase includes the addition of Ms. Holder to the list of named executive officers of 2012). These increases were in part due to significant base salary increases for Mr. Monaco when he was promoted to President and later to Chief Executive Officer and increases for Messrs. Bird and Wuori to recognize their increased responsibilities.

Awards under our medium and long-term incentive plans are generally targeted at the median of our peer group with the opportunity to realize a greater or lesser value depending on how Enbridge performs in the future. In addition to time-vesting provisions, the performance stock units have EPS and price-to-earnings (P/E) performance conditions and the performance stock options have three share price targets that must be met within a specified time period for the options to vest. Incentive stock options round out the long-term incentive plans and are an additional way to increase executives' equity stake in the company and align management interests with those of shareholders.

Key compensation decisions in 2012

The Board and the HRC Committee are responsible for overseeing the compensation principles and programs at Enbridge and approving compensation programs and payouts with assistance from independent outside advisers. In 2012, the following key compensation decisions were made:

•: developed a staged compensation plan for Mr. Monaco as incoming successor to recognize his appointment to President and then President & Chief Executive Officer;
•: increased the share ownership guidelines for the President & Chief Executive Officer position from 4 times to 5 times base salary;
•: negotiated Mr. Monaco's terms of employment which became effective October 1, 2012;
•: adjusted the base salaries and total compensation for Messrs. Bird and Wuori to reflect their expanded portfolios of responsibilities;
•: determined appropriate post-retirement vesting provisions for the 2012 long-term incentive awards for the retiring President & Chief Executive Officer;
•: reviewed and revised the peer groups used to benchmark named executives' compensation;
•: approved the design and implementation of the 2012 performance stock option plan; and
•: approved an adjustment to the calculated EPS for the 2012 short-term incentive plan to offset the negative short-term impact of the successful pre-funding actions on our 2012 EPS.

Compensation philosophy

Enbridge's vision is to be the leading energy delivery company in North America. While we may be viewed as having achieved elements of this vision, enhancing and sustaining this position remains a continuing long-term pursuit.

Operational performance is the cornerstone of assessing our performance as an organization. At Enbridge, operational performance covers personal, public and process safety, system reliability and environmental performance. Our goal is industry leadership in these areas and enhancing and promoting a culture of leading operational performance is a critical component in achieving this success. To reinforce this, employees at all levels (including all our named

2013 Management information circular 42

executives) have a direct linkage between operational performance and their short-term incentive awards, whether they are in a corporate or business unit role.

Our executive compensation programs are designed to motivate management to deliver exceptional value to shareholders through strong corporate performance and investing our capital in ways that minimize risk and maximize return, while always supporting our core business goal of delivering energy safely and reliably. Consistently applied, such stewardship should continue to generate attractive, risk adjusted returns and, in turn, provide for consistent and growing dividend distributions and related capital appreciation. Management has the commitment to shareholders to deliver steady, visible and predictable results in the short term and to operate our assets in a responsible manner.

The compensation programs at Enbridge reflect a blend of short, medium and long-term incentive awards to support our pay for performance philosophy (meaning there is a direct linkage between results and rewards). Relevant corporate and business unit performance measures are established for the short-term compensation plan that focus on the critical safety, system reliability, environmental and financial aspects of the business. The performance measures for the medium and long-term plans focus on overall corporate performance aligned with shareholder expectations for earnings growth and share price appreciation.

When assessing performance, the HRC Committee takes into consideration both the objective pre-defined performance metrics as well as qualitative factors not captured in the formal metrics. For example, a decision to complete a certain acquisition may have longer-term strategic benefits to the company which may not be reflected in the short-term performance metrics. Also playing a role are a number of market-based and earnings-based key performance indicators that compare Enbridge's results to a peer group and to the broader market over a one to 10 year time horizon. Therefore, the assessment of overall performance is based on a combination of the pre-defined performance metrics, the key performance indicators, as well as the qualitative aspects of management's responsibilities.

Compensation governance

Our compensation governance structure consists of the Board and the HRC Committee, with Mercer (Canada) Limited (Mercer), providing independent advisory support. The governance structure is reviewed regularly against best practices and regulatory guidance.

The Board is responsible for the oversight of the compensation principles and programs at Enbridge. The Board approves major compensation programs and payouts, including the compensation for the Chief Executive Officer. The HRC Committee approves the compensation for the other named executives.

The HRC Committee assists the Board in carrying out its responsibilities with respect to compensation matters by:

•: providing oversight and direction on human resources strategy, policies and programs for the named executives, senior management and our broader employee base, including compensation, pension and benefits as well as talent management, succession planning, workforce recruitment and retention;
•: ensuring the design of compensation programs and payouts align with sound risk management principles and practices and ensuring our management programs effectively address succession planning and employee retention;
•: reviewing and approving key financial, risk, strategic and operational objectives relevant to the compensation of the Chief Executive Officer and annually recommending the Chief Executive Officer's compensation to the Board, following an evaluation of the Chief Executive Officer's performance against these objectives;
•: approving the compensation of the named executives, following a review of their performance assessments and compensation recommendations provided by the Chief Executive Officer; and
•: reviewing the succession plan for the Chief Executive Officer and other key senior officers and long-range planning for executive development and succession to ensure leadership sustainability and continuity.

43 ENBRIDGE INC.

All members of the HRC Committee are independent under the independence standard discussed on page 25 of this circular. All members of the HRC Committee are knowledgeable and experienced individuals who have the necessary background in executive compensation to fulfill the HRC Committee's obligations to the Board and to our shareholders. Most members of the HRC Committee have significant experience as senior leaders of large organizations and have been long-standing members of Enbridge's HRC Committee or the members of the compensation committees of other large organizations. Their experience and skill levels are broad-based and include expertise in areas such as finance, mergers and acquisitions, governance, human resource management and business management. A variety of industry experience is represented with significant knowledge of the energy and oil and gas sectors. The chair of the HRC Committee is an audit committee financial expert as that term is defined by the US Securities Exchange Act of 1934 and also sits on our Audit, Finance & Risk Committee, along with three other members of the HCR Committee.

The members of our HRC Committee are Catherine L. Williams (chair), J. Lorne Braithwaite, J. Herb England, Charles W. Fischer, V. Maureen Kempston Darkes and Charles E. Shultz. For information on their Board Committee participation, please refer to page 15 of this circular.

Independent advice

Since 2002, Mercer, an independent compensation consultant, has advised the HRC Committee on compensation matters to ensure our programs are appropriate, market-competitive and continue to meet our intended goals. Advisory services include:

•: the competitiveness and appropriateness of our executive compensation programs;
•: annual total direct compensation for the President & Chief Executive Officer and his Executive Leadership Team;
•: governance of executive compensation; and
•: the HRC Committee's mandate and related Board Committee processes.

The HRC Committee chair reviews and approves our terms of engagement with Mercer every year. The terms specify the work to be done in the year, Mercer's responsibilities and its fees. Any other projects must be approved by the HRC Committee chair. Management can also retain Mercer on compensation matters from time to time. The chair of the HRC Committee must approve all services over $10,000. Management engages Mercer to provide assistance in compensation areas including:

•: competitive review of our various pension and benefit programs;
•: actuarial valuations of our defined benefit pension plans; and
•: renewal and pricing of our benefits plans.

While the HRC Committee takes the information and recommendations Mercer provides into consideration, it has full responsibility for its own decisions, which may reflect other factors and considerations.

Management and the HRC Committee engaged Mercer in 2012 to provide analysis and advice on various compensation matters. The following table provides a breakdown of services provided and fees paid to Mercer and all of its affiliates by Enbridge and all of its affiliates in 2012 and 2011:


	Nature of work	Approximate fees 2012 ($)	Approximate fees 2011 ($)

Executive Compensation-Related Fees1		348,166	233,366

All other Fees2		3,784,927	2,921,208

Total		4,133,093	3,154,574

1: Includes all compensation-related fees related to executive compensation associated with the Chief Executive Officer and his Executive Leadership Team. Additional services were provided in 2012 to support the Chief Executive Officer transition and the performance stock option grant.
2: Includes fees paid for other compensation matters that apply to the organization as a whole, such as pension actuarial valuations, renewal and pricing of benefit plans, and evaluating geographic market differences. Also includes risk brokerage service fees ($1,367,752 in 2012 and $578,186 in 2011) paid to Marsh Inc., a Mercer affiliate, for services provided to our operating affiliates.

With the retirement of Mr. Daniel and the appointment of Mr. Monaco as President & Chief Executive Officer, Hugessen Consulting was engaged to assist the HRC Committee in the development of a new Chief Executive Officer contract by providing an assessment of current best practices from a governance and risk perspective. This was a

2013 Management information circular 44

specific piece of research that was presented and discussed with the HRC Committee. The total fees for this engagement were $48,895. There were no other services provided by Hugessen Consulting to Enbridge during 2012.

Risk management

Enbridge is committed to ensuring that our compensation programs and policies are aligned with the long-term objectives of our shareholders. To accomplish this, we incorporate general risk management principles into all decision making processes across the organization and we regularly review our executive compensation programs through third party compensation consultants. This integration and review procedure helps ensure that our programs continue to support shareholder interests and regulatory compliance and are aligned with sound principles of risk management and governance.

The HRC Committee oversees the company's compensation programs from the perspective of whether they encourage individuals to take inappropriate or excessive risks that are reasonably likely to have a material adverse effect on the company.

The company uses the following compensation practices to mitigate risk:

•: we have a pay for performance philosophy that is embedded into our compensation design;
•: we believe our mix of pay programs, our approach to goal setting, establishing targets with multiple levels of performance and evaluation of performance results assist us in mitigating excessive risk-taking that could harm our value or reward poor judgment of our executives;
•: our compensation programs include a combination of short, medium and long-term elements that ensure our executives have the incentive to consider both the immediate and long-term implications of their decisions;
•: executives are compensated for their short-term performance using a combination of safety, system reliability, environmental, financial and customer and employee metrics that ensure a balanced perspective and are a mix of both leading and lagging indicators;
•: performance thresholds are established that include both minimum and maximum payouts;
•: stock award programs vest over multiple years and are aligned to overall corporate performance that drives superior value to shareholders; and
•: share ownership guidelines ensure executives have a meaningful equity stake in the company and align their interests with those of shareholders.

The HRC Committee has discussed the concept of risk as it relates to our compensation programs and does not believe our programs encourage excessive or inappropriate risk taking.

Clawback policy

The Board of Directors is in the process of establishing a policy that will enable it to recover, from current and former executives, certain incentive compensation amounts that were awarded or paid to such individuals based upon the achievement of financial results that are subsequently materially restated or corrected, in whole or in part, if such individuals engaged in fraud or willful misconduct that resulted in the need for such restatement or correction and it is determined that the incentive compensation paid to the individuals would have been lower based on the restated or corrected results. The Board expects this policy to be in place by the end of the first half of 2013.

Hedging policy

Our insider trading and reporting guidelines, among other things, prohibit directors, officers and employees from engaging in the following, in respect of any securities of Enbridge or its subsidiaries:

•: any form of hedging activity;
•: any form of transaction of options (other than exercising options in accordance with the plans);
•: any other form of derivative (including "puts" and "calls"); and
•: "short selling" (selling securities that he or she does not own).

We provide incentive benefits to some of our officers and employees to voluntarily acquire Enbridge securities as a long term incentive to align the commitment, interests and day-to-day activities and performance of those persons with the

45 ENBRIDGE INC.

long term interests of Enbridge and its shareholders. Speculating in securities of Enbridge or its subsidiaries or taking derivative positions which delink the intended alignment of interests is prohibited.

Approach to executive compensation

Our approach to executive compensation is set by the HRC Committee and approved by the Board. Our programs are designed to accomplish three things:

•: attract and retain a highly effective executive team;
•: align their actions with our business strategy and the interests of our shareholders; and
•: reward them for short, medium and long-term performance.

Benchmarking to peers

We benchmark our executive compensation programs against a group of similar companies in Canada and the US to ensure we are rewarding our executives at a competitive level.

In 2012, the HRC Committee engaged Mercer to undertake a review of the peer companies utilized for executive compensation benchmarking purposes, to ensure their continued appropriateness as Enbridge has experienced significant growth in recent years. As a result, several adjustments were made to both the Canadian and US peer groups.

The Canadian companies identified are large pipeline, energy, utility and railway companies that are similar to us in size, utilizing assessments of enterprise value and revenues, and in risk profile. Together they reflect the Canadian business environment that we operate in.

The US companies are mainly oil and gas pipelines and utilities because the US energy sector is much larger and has more depth than Canada's.

Peer group


	Canada	US

Canadian National Railway Company		Consolidated Edison, Inc.*
Canadian Natural Resources Limited*		Dominion Resources, Inc.*
Canadian Pacific Railway Limited		Duke Energy Corporation*
Cenovus Energy Inc.*		Energy Transfer Partners, L.P.*

Encana Corporation*		Enterprise Products Partners L.P.*
Husky Energy Inc.		Exelon Corporation*
Imperial Oil Limited*		Kinder Morgan, Inc.*
Nexen Inc.		Nextera Energy, Inc.*

Suncor Energy Inc.		Plains All American Pipeline, L.P.*
Talisman Energy Inc.		PG&E Corporation
TransCanada Corporation		PPL Corporation
		Sempra Energy

		The Southern Company*
		Spectra Energy Corp
		The Williams Companies, Inc.

*: New for 2012

We believe this new group of peer companies better aligns with an enterprise value and other comparative purposes.

How we compare


	Canada	US

Enterprise value	Above 75th percentile	Between 50th and 75th percentile

Revenue	At 75th percentile	Above 75th percentile

Total assets	Between 50th and 75th percentile	Between 25th and 50th percentile

Number of employees	Between 50th and 75th percentile	Between 25th and 50th percentile

Market capitalization1	Between 50th and 75th percentile	Above 75th percentile

1: As of September 30, 2012. All other information is based on most recently reported data.

2013 Management information circular 46

Setting compensation targets

Although we target overall total compensation at the 50th percentile, we establish base pay between the median and the 75th percentile, considering the skill, competency and experience of each senior executive. Executives who are demonstrating superior performance and consistently achieving significant results have their base pay aligned at the higher end of the percentile range. We link targets for short, medium and long-term incentives to base salary levels.

For each of the named executives, we target total direct compensation at the median of our comparator companies in North America. Actual total direct compensation depends on performance. The responsibilities of our named executives are North American in scope, therefore, we weight the Canadian and US peer groups equally.

At risk compensation

The graphs below show the compensation mix for our current President & Chief Executive Officer and an average for our other named executives. The short, medium and long-term incentives are considered to be at risk because their value is based on performance and is not guaranteed. In 2012, 90% of the target total direct compensation for the current President & Chief Executive Officer and an average of 85% for the other named executives was at risk, directly aligning corporate, business unit and individual performance with the interests of shareholders. The at risk component of compensation increased in 2012 over 2011 because of the 2012 grant of performance stock options (a 5-year grant covering the period of 2012 – 2016). Please see page 41 for a list of the named executives.

President & Chief Executive Officer		Average for Other Named Executives

Share ownership

It is important for all of our officers, including executives, to have a meaningful equity stake in the company. Owning Enbridge shares is a tangible way to align the interests of our officers with those of our shareholders.

Target ownership is a multiple of base salary, depending on position level, and officers are required to meet the target within four years of being appointed to the position. Officers can acquire Enbridge shares by participating in the employee savings plan, exercising stock options or by making personal investments in Enbridge common shares. Personal holdings, or Enbridge shares held in the name of a spouse, dependent child or trust, all count toward meeting the guidelines. Stock options do not count towards meeting the guidelines.

	Target and actual share ownership as of December 31, 2012

	Executive	Target ownership	Actual ownership	Meets requirements

Patrick D. Daniel1		4x base salary	46x base salary	Yes

Al Monaco2		5x	5x	Yes

J. Richard Bird		2x	16x	Yes

Stephen J. Wuori		2x	16x	Yes

David T. Robottom		2x	5x	Yes

Janet Holder		2x	6x	Yes

1: Mr. Daniel retired as Chief Executive Officer effective September 30, 2012. His target and actual ownership are shown as at that date.
2: Mr. Monaco's target ownership increased from 2x base salary to 5x base salary upon becoming President & Chief Executive Officer effective October 1, 2012.

47 ENBRIDGE INC.

Pay for performance

Performance is foundational to our executive compensation programs. The programs are designed to motivate management to achieve the reliable business model and superior returns that shareholders expect, with a focus on the longer term, while ensuring that the critical operational performance of the business is achieved. The Board of Directors reviews our short, medium and long-term business plans and the HRC Committee links the compensation programs to these timeframes. This ensures that management is focused on delivering value to shareholders not only in the short-term, but also continued performance over the longer term. The performance of our peer group is also considered.

Annual decision making process

The HRC Committee reviews and approves the compensation plans and pay levels for all the named executives. The HRC Committee reviews and recommends the compensation plans and pay level for the President & Chief Executive Officer to the Board. The table below shows how we make compensation decisions.

Components of executive compensation

Total executive compensation is made up of six components.

Base salary

Short-term incentive

Medium-term
incentives

Longer-term
incentives

Retirement benefits

Other benefits

• annual base pay

• annual cash bonus

• performance stock units

• incentive stock options
• performance stock options

• pension plans
• other retirement benefits

•   savings plan
•   perquisites
•   medical, dental and insurance

Base salary

Our base salaries offer fixed compensation for performing day-to-day responsibilities, while balancing the individual's role and competency, market conditions and issues of attraction and retention.

Short-term incentive

The short-term incentive plan is an annual bonus plan, paid out in cash. It is designed to motivate management to achieve corporate, business unit and individual objectives tied to executing our business strategy and to reward them according to their achievement for the year.

Each executive's target award and payout range reflect the level of responsibility associated with the role, as well as competitive practice, and is calculated as a percentage of base salary.

2013 Management information circular 48

It is critically important to ensure all of our executives are incented to achieve not only financial results but also operational results in the areas of safety and environmental performance, as well as customer and employee-based measures. For this reason, our short-term incentive awards are paid out based on performance against a combination of corporate, business unit and individual goals. To ensure alignment between each executive and the execution of the overall business strategy, all executives have a significant component of their incentive tied to operational business unit results as well as corporate measures. Operational results focus on the safe and reliable operation of our systems, the health and safety of our employee and contractor workforce and our environmental performance. For those executives who have primary responsibility for overall corporate performance, the corporate performance metrics are given more weight. Business unit performance metrics are given the most weight for executives with primary responsibility within an operating business unit.

Short-term incentive targets (as of December 31, 2012):



	Target award	Payout range	Performance measures/weightings
	(as a % of base salary)		Corporate	Business unit	Individual

Patrick D. Daniel	90%	0 – 180%	60%	20%	20%
Al Monaco1	90%	0 – 180%	60%	20%	20%
J. Richard Bird2	65%	0 – 130%	60%	20%	20%
Stephen J. Wuori2	65%	0 – 130%	25%	50%	25%
David T. Robottom	50%	0 – 100%	60%	20%	20%
Janet Holder	50%	0 – 100%	25%	50%	25%

1: Mr. Monaco's short-term incentive award target was increased from 50% of base earnings for January 1, 2012 to February 29, 2012 to 75% on March 1, 2012, to reflect his appointment as President, and further increased to 90% on October 1, 2012, to reflect his appointment as President & Chief Executive Officer. Mr. Monaco's short-term incentive award payment for 2012 was prorated accordingly.
2: Messrs. Bird and Wuori's short-term incentive award target increased from 50% to 65% as of March 1, 2012 to reflect increases in their portfolio of responsibilities. Messrs. Bird and Wuori's short-term award payments for 2012 were prorated accordingly.

We calculate the awards using an actual performance multiplier that ranges anywhere from 0 to 2, depending on whether the combination of goals has been met.

Use of discretion

The President & Chief Executive Officer can recommend an adjustment to the calculated short-term incentive award for his direct reports up or down when he feels it is appropriate, to reflect extraordinary events and other things not contemplated in the original measures or targets. The HRC Committee must approve the Chief Executive Officer's recommendations.

The HRC Committee can adjust the calculated short-term incentive award for the President & Chief Executive Officer up or down at its discretion. It can also change or waive the eligibility criteria, performance measures and the target and maximum award levels when it believes it is reasonable to do so, considering things like key performance indicators and the business environment in which the performance was achieved.

Medium and long-term incentives

Our medium and long-term incentives for executives include three plans: the performance stock unit plan, the performance stock option plan and the incentive stock option plan. These plans motivate executives to deliver strong performance and reward them for achieving earnings targets, maintaining top quartile price-to-earnings performance compared to our peers and appreciation in our share price over the longer term. Prior grants are not considered in determining future grants.

49 ENBRIDGE INC.

The three plans that apply to executives all have different terms, vesting conditions and performance criteria. This mitigates the risk associated with our compensation plans by ensuring our executives do not have an incentive to produce only short-term results for individual profit. This approach benefits shareholders and helps to maximize the retention value of the medium and long-term incentives granted to executives.


	Performance stock unit plan	Performance stock option plan	Incentive stock option plan

Term	Three years	Eight years	Ten years

Description	Phantom Enbridge shares with performance conditions that affect payout	Options to acquire Enbridge common shares once performance conditions met	Options to acquire Enbridge common shares

Frequency	Granted every year	Granted approximately every five years	Granted every year

Performance Conditions	Two performance conditions, weighted 50% each: • Earnings per share relative to a target set at the start of the term; and • Price to earnings performance relative to peers	2012 grant1: • Three share price targets that must be met within a defined time period • Performance vesting weighted at 40%/40%/20%	n/a

Vesting	Units mature in full after three years	Options vest 20% per year over five years, starting on the first anniversary of the grant date	Options vest at 25% per year over four years, starting on the first anniversary of the grant date

Payout	Paid out in cash at the end of three years based on: • the market value of an Enbridge share at the end of three years; and • the performance conditions	Participant acquires Enbridge common shares at the exercise price defined at the time of grant (fair market value)	Participant acquires Enbridge common shares at the exercise price defined at the time of grant (fair market value)

1: The 2007 grant had two share price targets with performance vesting equally weighted at 50%/50%.

The table below shows the target amounts that we grant in medium and long-term incentives and the amount that each plan contributes to that total, in each case as a percentage of base salary.

Long-term incentive targets (as of December 31, 2012):


	Target medium and long-term incentive grant (as % of base salary)	Amount each plan contributes to total target grant (as % of base salary)

		Performance stock units	Performance stock options	Incentive stock options

President & Chief Executive Officer	330%	115%	100%	115%

Executive Vice-President, Chief Financial Officer & Corporate Development	250%	87.5%	75%	87.5%

President, Liquids Pipelines & Major Projects	250%	87.5%	75%	87.5%

Executive Vice President & Chief Legal Officer	200%	70%	60%	70%

Executive Vice-President, Western Access	200%	70%	60%	70%

Medium and long-term incentive grants are determined as follows:

Performance stock units

Performance stock units give our executives the opportunity to earn up to two times the value of their units when they mature after three years, by achieving certain performance measures. We typically grant performance stock units annually, at the beginning of the year.

2013 Management information circular 50

We currently use two performance measures, each weighted at 50%:

•: Earnings per share (EPS): This measure represents a commitment to Enbridge shareholders to achieve earnings that meet or exceed the average industry growth rates projected at the time of grant.
•: Price-to-earnings (P/E) ratio: We use this measure because it is a strong reflection of how shareholders view our stock and our growth potential relative to our peers. For this measure, we compare ourselves against the following group of companies, chosen because they are all capital market competitors, have a similar risk profile and operate in a comparable sector.


	P/E ratio comparator group

Ameren Corporation		OGE Energy Corp.
Canadian Utilities Limited		ONEOK, Inc.
Centerpoint Energy, Inc.		PG&E Corporation
Emera Incorporated		Sempra Energy
Fortis Inc.		Spectra Energy Corp.
National Fuel Gas Company		TransAlta Corporation
NiSource Inc.		TransCanada Corporation

We calculate the payout at the end of the three year term using an actual performance multiplier that ranges from 0 to 2.0 depending on whether the performance conditions are met. The final Enbridge share price at the end of the term is the weighted average trading price of an Enbridge common share on the TSX or New York Stock Exchange for the last 20 days before the end of the term.

Performance stock options

Performance stock options are granted approximately once every five years and give executives the opportunity to buy Enbridge common shares at the exercise price specified at the time of the grant, as long as share price targets are met by a certain date. We set the targets before we grant the performance stock options, basing them on growth rates of adjusted earnings that represent exceptional (top quartile) performance and historical price-to-earnings ratio information for the industry.

2007 grant

In 2007, we granted performance stock options to the executive officers at the time. In 2008, we granted performance stock options to Mr. Monaco when he was appointed to the executive team.


Grant date	Number of performance stock options granted1	Exercise price1	Share price targets1	Must be exercised by

August 15, 2007	4,690,0002	$18.29 per share	$25 and $27.50 by February 2014	August 15, 2015

February 19, 2008	500,000	$20.21 per share	$25 and $27.50 by February 2014	August 15, 2015

1: The number of performance stock options and the exercise price and share price targets have been adjusted to reflect the Enbridge stock split of May 2011.
2: This number represents the total performance stock options granted to the current named executive officers and to executive officers who have now retired.

51 ENBRIDGE INC.

The vesting of performance stock options is contingent on both a time vesting provision and the share price targets being met. Performance stock options time vest in equal annual installments over a five-year period; however, none actually vest until the share price performance hurdles are achieved. As of December 31, 2012, both share price targets have been met. Therefore 100% of the 2007 grant is exercisable and 80% of the 2008 grant is exercisable.

2012 grant

In August 2012, executive officers at the time, excluding Mr. Daniel, received a grant of performance stock options to cover the period of 2012 - 2016. The vesting of performance stock options is contingent on both a time vesting provision and the share price targets being met. Performance stock options time vest in equal annual installments over a five-year period; however, none actually vest until the share price performance hurdles are achieved. The performance criteria are such that, of the portion that has already time-vested, 40% will vest at $48.00; 80% at $53.00 and 100% at $58.00.

Details of this grant for the named executives are provided on page 61.


Grant date	Number of performance stock options granted1	Exercise price	Share price targets	Must be exercised by

August 15, 2012	3,542,500	$39.86 per share	$48, $53 and $58 by February 2019	August 15, 2020

1: This number represents the entire grant, of which 2,910,100 options were granted to named executive officers. None of the 2012 grant is exercisable as of December 31, 2012.

Incentive stock options

An incentive stock option gives a participant the option to buy one Enbridge common share at some point in the future at the exercise price defined at the time of grant.

We typically grant incentive stock options in February of each year to both Canadian and US members of senior management who are eligible to participate in the incentive stock option plan. Options granted to US employees can either be qualified or non-qualified, as defined by the US Internal Revenue Code.

Incentive stock options typically vest in equal installments over a four-year period. The maximum term of a stock option is ten years, but the term can be reduced if the executive leaves the company. Please see page 74 for further details.

The exercise price of an incentive stock option is the weighted average trading price of an Enbridge common share on the TSX for the last five trading days before the grant date. If the grant date is during a trading blackout period, we will adjust the grant date to no earlier than the sixth trading day after the trading blackout period ends. We do not backdate stock options.

We may grant incentive stock options to executives when they join the company, and would normally grant them on the executive's date of hire. If the hire date falls within a blackout period, the grant is delayed until after the end of the blackout period.

Stock options granted and outstanding as of March 5, 2013


Stock options outstanding
• stock option plans	33,599,757
• legacy incentive stock option plan (2002)	3,639,260
• Total for all stock option plans (incentive stock options and performance stock options)	4.60% of total issued and outstanding shares

Transferring and assigning stock options

The holder of an option cannot transfer or assign it other than by will, or as allowed by the laws of descent and distribution.

Share settled options

When an employee exercises an option they may receive Enbridge common shares having a fair market value equal to the "in-the-money" value of the option at the time it is exercised. In this case, the lesser number of Enbridge common shares issued and not the number of underlying Enbridge common shares reserved for issuance under the option will be deducted from the current option plan.

2013 Management information circular 52

Making changes to the stock option plans

The Board can make changes to the stock option plans, in whole or in part, as long as the regulators approve the changes; however shareholders must also approve the following changes:

•: changing the number of Enbridge shares that can be issued under the stock option plans;
•: removing or exceeding the insider participation limit;
•: reducing the grant price of an option;
•: cancelling or reissuing an option at a lower grant price;
•: extending the term of an option;
•: allowing someone who isn't a full time employee to participate in the stock option plans;
•: changing the rules related to transferring or assigning options; and
•: changing the amendment provisions of the stock option plans.

In 2012, the Board approved changes to the proration of performance stock options upon retirement to reflect their view that a grant of performance stock options relates to a five calendar year period even though the grant date occurs partway through the calendar year. These changes are permitted by the terms of the plan and do not require shareholder approval. The changes are:

Plan text before amendment	Plan text after amendment

• We prorate the performance stock options for the period of active employment in the five year period starting on the grant date.	• We prorate the performance stock options for the period of active employment in the five year period starting January 1 of the year of the grant.
• These prorated options can be exercised until the earlier of three years after retirement and the expiry of the term.	• These prorated options can be exercised until the later of three years after retirement or 30 days after the date the share price targets must be met (or up to the date the options expire, whichever is earlier).

Adjustments

The Board or the HRC Committee may make the following adjustments to the options or to the Enbridge shares that can be issued under the stock option plans upon the occurrence of certain events, including the payment of a stock dividend or a restructuring of our share capital:

•: increase or decrease the number or change the kind of shares reserved under the stock option plans or that can be issued when outstanding options are exercised;
•: increase or decrease the option grant price per Enbridge share; and
•: make changes to how installments of options vest and can be exercised.

The Board can also adjust the number of shares available under the stock option plans, the option price per Enbridge share and the option period, to allow our shareholder rights plan to continue to operate.

Please see page 74 for further information regarding our stock option plans, such as stock option plan restrictions and termination provisions.

Retirement benefits

As of January 1, 2000 (or the time of hire or promotion to a senior management position if after that date) the named executives joined the senior management pension plan, which is a non-contributory defined benefit plan that pays out an enhanced retirement income to all senior management employees. Before becoming members of this plan, certain named executives participated in a non-contributory defined benefit or defined contribution pension plan.

53 ENBRIDGE INC.

Defined benefit plan

The graphic below shows how we calculate the retirement benefit payable under the defined benefit pension plan applicable to the named executives:

Some key terms of the defined benefit plan

•: Retirement age: Executives can retire with an unreduced pension at age 60, or as early as age 55 if they have 30 years of service. If they have less than 30 years of service, they can still retire as early as age 55, but their retirement benefit is reduced by 3% per year before age 60;
•: Adjustment for inflation: Retirement benefits are indexed at 50% of the annual increase in the consumer price index;
•: Survivor benefits: the pension is payable for the life of the member. If the member is single at retirement, 15 years of pension payments are guaranteed. If the member is married at retirement and dies before their spouse, 60% of the pension will continue to be paid to the spouse for his/her lifetime; and
•: Flexibility: To attract and retain executives we can negotiate additional years of credited service or higher pension accruals, subject to approval by the HRC Committee.

Defined contribution plan

The defined contribution pension plan is a non-contributory pension plan. The level of contribution varies, depending on age and years of service.

Other retirement benefits

•: we prorate our executives' short-term incentive awards for the period of active employment in their last year;
•: we prorate their unvested performance stock units for the period of active employment during the term of the grant. The units continue to mature according to the terms of the performance stock unit plan;
•: we prorate their performance stock options for the period of active employment in the 5 year period starting January 1 of the year of grant. They can exercise these options until the later of three years after retirement or 30 days after the date by which share price targets must be met (or up to the date the option expires, whichever is earlier), as long as the share price targets are met; and
•: their unvested incentive stock options continue to vest according to the terms of our stock option plans. They can exercise these options up to three years after retirement, or up to the date the option expires (whichever is earlier).

Other benefits

Our savings plan, perquisites and benefits plans are key elements of our total compensation package for our named executives.

Savings plan

Our savings plan encourages share ownership by matching employee contributions of up to 2.5% of base salary (5% in the US) toward the purchase of Enbridge shares. The named executives participate in this plan along with all other employees.

2013 Management information circular 54

Perquisites

The named executives receive an annual perquisite allowance to offset expenses related to their position. This includes the cost of owning and operating a vehicle, parking and recreational clubs. These allowance levels are reviewed regularly for competitiveness. The named executives are also reimbursed for a portion of costs for personal financial planning.



	Perquisite allowance	Financial planning reimbursement

Patrick D. Daniel	$49,500	50% up to $10,000
Al Monaco1	$34,875	50% up to $10,000
J. Richard Bird	$35,000	50% up to $5,000
Stephen J. Wuori	$35,000	50% up to $5,000
David T. Robottom	$30,000	50% up to $5,000
Janet Holder	$35,000	50% up to $5,000

1: Mr. Monaco's perquisite allowance was prorated for 2012 with an adjustment to his annual
allowance of $30,000 (from January to September) to $49,500 (from October to December).

Medical, dental and insurance benefits

Medical, dental and insurance benefits are available to meet the specific needs of individuals and their families. The named executives participate in the same plan as all other employees. The plans are structured to provide minimum basic coverage with the option of enhanced coverage at a level that is competitive and affordable.

The HRC Committee reviews our retirement and other benefits regularly. These benefits are a key element of a total compensation package and are designed to be competitive and reasonably meet the needs of executives in their current roles and when they retire from Enbridge.

In 2012 a complete review of our pension and benefit programs was undertaken to ensure they were meeting the needs of both the company and our employees. The review provided confirmation that our programs are designed with enough flexibility to meet the needs of our current and future workforce, are market competitive and are designed to be financially sustainable over time. While there are no program design changes required at this time, there is an opportunity to increase the level of communication and education that we provide to our employees with respect to these programs, and this will be an area of focus in 2013.

Compensation changes in 2013

The Committee reviews Enbridge's compensation philosophy and practices every year with assistance from Mercer, an independent compensation consultant, to ensure they are appropriate, competitive and continuing to meet our intended goals. There are no major compensation design or program changes approved by the HRC Committee for implementation in 2013. Based on the annual compensation benchmarking review for our senior executive positions conducted by Mercer in the fall of 2012, there will be some modest changes to 2013 short-term incentive targets for Mr. Robottom and Ms. Holder (from 50% to 60% of base salary) and from 90% to 100% of base salary for Mr. Monaco. Mr. Monaco's long-term incentive target has increased from 300% to 330% for 2013. These changes are made to maintain their competitive market positioning.

As part of our ongoing assessment we will continue to review our pay programs during the course of 2013. Any changes will be brought forward to the HRC Committee and the Board for decision. Any approved changes would come into effect in 2014.

2012 performance

Enbridge made good progress on many fronts in 2012 as we continued to build a solid and secure foundation for our future growth.

We achieved strong growth in earnings and cash flow in 2012, achieving our guidance range. Adjusted EPS rose 11% in 2012 to $1.62 per common share, building on an 11% increase in 2011 and a 13% increase in 2010.

55 ENBRIDGE INC.

Having entered 2012 with $12 billion in commercially secured growth projects in execution, we steadily added to that portfolio during the year and exited 2012 with a total of $26 billion in commercially secured growth projects over 2012 to 2016. These opportunities alone are expected to drive 10% plus average annual EPS growth through 2016.

In December 2012, we announced our 2013 guidance for adjusted earnings of $1.74 to $1.90 per share, the mid-point of the guidance range which represents an increase of approximately 12% over 2012. Also in December, based on our strong results and the Board's confidence in our long-term outlook, the Board approved an increase in the quarterly dividend of 12% effective March 1, 2013. Enbridge has increased its dividend by an average of 12% per year over the last ten years, and we have paid dividends for 60 years.

The majority of notable growth projects that we announced in 2012 are grouped within four Liquids Pipelines capital programs, which are designed to address the changing fundamentals of supply and market access. Combined, the four programs – US Gulf Coast Access; Eastern Access; Western Access; and Light Oil Market Access – effectively respond to the needs of our customers, as do the secured capital projects that we currently have underway to expand our Alberta regional infrastructure and our Bakken infrastructure in Saskatchewan and North Dakota.

In 2012, we took another step in the execution of our strategy to establish a strong position in the Canadian Midstream business when we entered into a midstream services relationship with Encana Corporation to develop gas gathering and compression facilities in the Peace River Arch region in northwest Alberta.

Also in 2012, we committed $600 million to expand Enbridge Gas Distribution Inc.'s natural gas distribution system in the Greater Toronto Area (GTA) to meet the demands of growth in the GTA, and we advanced our strategic objective to build a presence in the power transmission sector when we filed with joint venture partners for regulatory approval to acquire interests in Upper Canada Transmission Inc., which intends to bid for the opportunity to develop a new transmission line in northern Ontario.

We continued to grow our renewable and alternative energy portfolio in 2012 through the acquisition and start-up of the 50-MW Silver State North Solar Project in Nevada and the acquisition of a 50% interest in the 150-MW Massif de Sud Wind Project in Quebec. By year-end 2012, we had interests in about 1,365 MW – and owned almost 1,000 MW – of renewable and alternative energy projects. Our ownership interests in these projects provide enough energy to power approximately 275,000 homes.

With a growing slate of growth projects, Enbridge continued to demonstrate a strong competency in major project execution in 2012. With more than 20 major projects underway during the course of the year, the majority remained on schedule and on, or below, budget. We were also able to successfully bring onboard more than 3,700 employees in Canada and the US to effectively support our current and future growth.

In 2012, we also continued to make solid progress in further reinforcing safety and operational integrity across all of Enbridge's business units. We are doing this through our comprehensive operational risk management assessment and planning initiative, in which we are identifying and implementing further risk mitigation strategies to provide assurance that Enbridge will achieve its safety, integrity and environmental protection objectives. Our goal is to achieve top-quartile performance, along several safety and integrity dimensions. Executive oversight of this initiative is through our Operations and Integrity Committee, which is now the most critical committee in the company. We have redefined accountability, set performance targets and added technical staff. We have also established an Operational Risk Management Plan (ORM Plan), which is a roadmap of programs that are required to sustain an industry-leading position. We will obtain independent verification of our performance, and the results will be monitored by the Board.

Enbridge was recognized throughout 2012 for our Corporate Social Responsibility performance. For the fifth year in a row, Enbridge was included in the Global 100 Most Sustainable Corporations in the World ranking. We were also included on the 2012/2013 Dow Jones Sustainability World Index and the Dow Jones Sustainability North America Index and made a constituent of the 2012/2013 FTSE4Good Index. Enbridge was also included on the 2012 Carbon Disclosure Leadership Index and was named one of Canada's Greenest Employers and one of Canada's Top 100 Employers for 2013.

All of these developments had an impact on our share performance in 2012. Our common shares reached a 52-week trading high of $43.05 on the TSX on December 31st, before closing that day, and the year at $43.02 per common share.

2013 Management information circular 56

Enbridge's share price has outperformed the S&P/TSX Composite Index by 10% per year on average over the past 10 years. Since our inception as a publicly traded entity over 60 years ago, we have delivered an average annual total shareholder return of 15%, outperforming the TSX Composite Index by almost 6% over a similar timeframe.

Enbridge Performance Relative to S&P/TSX Composite Index As at December 31, 2012

2012 pay decisions

The HRC Committee reviewed the performance, business environment and peer group comparisons and recommended the 2012 compensation for both the former and current President & Chief Executive Officers. The HRC Committee also reviewed and approved the recommendations of the former President & Chief Executive Officer for the remaining named executives.

Base salary

On April 1, 2012, Messrs. Daniel and Robottom received modest base salary increases to maintain their competitive position within the market. A larger increase was awarded to Ms. Holder to better align her positioning relative to the competitive market. In March 2012, the portfolios of responsibilities for Messrs. Bird and Wuori were expanded and their base salaries were adjusted accordingly to appropriately position them to the market. Mr. Monaco received a base salary increase of 52% in March 2012 when he was promoted to President, and he received an additional base salary increase of 25% when he was appointed President & Chief Executive Officer in October 2012.

Base salary



Base salary *as of December 31, 2012*	2012 base pay ($)	% increase from 2011	2011 base pay ($)	% increase from 2010

Patrick D. Daniel1	1,330,000	4.0%	1,279,000	3.0%

Al Monaco2	1,000,000	90.5%	525,000	5.0%

J. Richard Bird3	725,000	25.7%	576,800	3.0%

Stephen J. Wuori3	700,000	15.6%	605,480	3.5%

David T. Robottom	460,830	4.0%	443,100	5.0%

Janet Holder	449,400	7.0%	420,000	5.0%

1: Mr. Daniel retired as Chief Executive Officer effective September 30, 2012. His 2012 base pay is shown as at that date.
2: Mr. Monaco's overall pay increase reflects his appointment as President on February 27, 2012 and President & Chief Executive Officer effective October 1, 2012, and the pay increases to $800,000 and $1,000,000 associated with those appointments.
3: Messrs. Bird and Wuori's pay increases reflect increases in their portfolio of responsibilities effective March 1, 2012.

Short-term incentive

Our short-term incentive is awarded based on performance against a combination of corporate, business unit and individual objectives that were established and approved at the beginning of 2012. In February 2013, the HRC Committee determined awards for the named executives under the short-term incentive plan of $4,121,680 including

57 ENBRIDGE INC.

$1,239,040 to the former President & Chief Executive Officer and $1,033,550 to the current President & Chief Executive Officer.

Corporate performance

Our 2012 corporate performance was measured by adjusted EPS. This is a metric that focuses on return to shareholders and is aligned with how investors and security analysts assess Enbridge's performance on an annual basis. Adjusted EPS is closely aligned with the company's targets and objectives and is consistent with information reported regularly to the investor community. It is a metric that is understandable from an employee perspective. The annual Board-approved budget establishes the target (1.0 multiplier) for this metric. The minimum (0) and maximum (2.0) multipliers are set using the low end and top end of the external guidance range that is publicly disclosed prior to the beginning of 2012. The adjusted EPS metric represents a significant component of our corporate named executives' short-term incentive award, ranging from 25%-60%.

Our 2012 adjusted EPS guidance range was $1.58 – $1.74 (with target equal to $1.66) as approved by the Board prior to the beginning of 2012. Actual performance was $1.62. Consistent with our financial reporting and public disclosure of results, adjusted earnings excludes the impact of non-recurring or non-operating items. Approximately $639 million of net adjustments were made to arrive at adjusted earnings of $1,249 million, including adjustments for mark-to-market gains/(losses) and tax on intercompany gains and sales.

The HRC Committee also considered our performance compared to other companies in our performance stock unit peer group and companies in the TSX60 and TSX Composite indices, as measured by dividend per share growth, total shareholder return and reward to risk over the past one, three, five and ten year periods. Enbridge's 2012 performance on all of the key performance indicators remained strong:

•: 11% EPS growth;
•: 15% dividend per share growth from 2011 (one of the highest in our peer group);
•: reward to risk ratio at the 93rd percentile of the peer group; and
•: total shareholder return in all periods (one year: 89th percentile; three year: 98th percentile; five year: 100th percentile; and 10 year: 100th percentile).

Use of discretion

During 2012, Management undertook, with Board of Director approval, a supplementary financing plan that included $2.8 billion of common equity, preferred equity and debt pre-funding actions that were not provided for in the original budget, prompted by the significant expansions to the company's five-year growth capital plan, which emerged over the course of the year.

Although these actions had an adverse impact on 2012 EPS, they were necessary and prudent steps to support the medium and long-term objectives of the company.

The HRC Committee approved an adjustment to the calculated EPS result utilized for the corporate performance multiplier for short-term incentive purposes only, to better align the short-incentive awards for employees with the positive near-term and long-term outcomes for shareholders and the company. Adjusting out the impact of the specific pre-funding actions noted above, resulted in an adjusted EPS of $1.676 (versus $1.62 per share) and a short-term corporate multiplier of 1.20 out of 2.0. This adjustment is reflected in the detailing of each named executive's compensation, beginning on page 62.

Business unit performance

Business unit performance is assessed relative to a scorecard of metrics and targets established by each business leader and their senior management teams at the start of the year. Scorecards are reviewed across the enterprise by the Executive Leadership Team. Scorecards include a range of financial and operational metrics that include personal, public and process safety, reliability of our systems and environmental performance. Customer service and satisfaction measures and employee metrics linked to employee engagement and our ability to attract and retain the talent that we need to execute on our business strategies, can also be included. Operational performance is a critically important focus for all employees, whether they are in direct operating roles or supporting functions. To reinforce that importance, all of the employees and executives have a significant element of their short-term incentive calculation tied to operational results. For the named executives who are primarily responsible for an operating business unit, 50% of their annual

2013 Management information circular 58

short-term incentive is tied to their business unit scorecard(s). For the named executives whose role is in a corporate function, 40% of their business unit component of their short-term incentive is an average of the non-financial operating metrics of the operating business units.

The following is an overview of the type of metrics and overall performance multipliers used for each named executive this year:



	Business unit	Metrics	Performance multiplier (0-2)

Patrick D. Daniel	• Business unit composite	• non-financial operating measures for the combined enterprise	1.46

Al Monaco	• Business unit composite	• non-financial operating measures for the combined enterprise	1.46

J. Richard Bird	• Corporate office	• financial (corporate costs) • full range of non-financial operating measures for the combined enterprise	1.47
		• employee retention
	• Green Energy, International and Energy Marketing	• financial and operating measures for the Green Energy, International and Energy Marketing business unit

Stephen J. Wuori	• Liquids Pipelines	• financial and operating measures for the Liquids Pipelines and Major Projects business units	1.31

David T. Robottom	• Corporate office	• financial (corporate costs)	1.46
		• full range of non-financial operating measures for the combined enterprise
		• employee retention

Janet Holder	• Western Access	• financial measures related to the Western Access business unit	1.33
		• full range of operating measures for the Western Access business unit

Individual performance – objective setting

In consultation with Mr. David A. Arledge, Chair, Board of Directors, and Ms. Catherine L. Williams, chair, HRC Committee, the former President & Chief Executive Officer's individual 2012 objectives were established at the start of the year, taking into consideration the company's financial and strategic priorities and Chief Executive Officer succession. The Chief Executive Officer and the President established individual objectives for the other members of the Executive Leadership Team for 2012 at the start of the year, basing them on strategic and operational priorities related to their portfolios and other factors. Upon transition to the role of President & Chief Executive Officer in October 2012, Mr. Monaco's individual objectives for the balance of the year were established in consultation with Mr. Arledge and Ms. Williams.

The discussion of each named executive's individual and business unit performances starts on page 62.

59 ENBRIDGE INC.

Short-term incentive calculations

The table below shows how we calculated each named executive's overall performance multiplier in 2012.



	A – Corporate performance					B – Business unit performance					C – Individual performance					Overall performance multiplier1

	Weight	×	Corporate multiplier	=	Total A	Weight	×	Business Unit Multiplier	=	Total B	Weight	×	Individual Multiplier	=	Total C	Total A+B+C

Patrick D. Daniel	60%		1.20		0.72	20%		1.46		0.29	20%		1.85		0.37	1.38

Al Monaco	60%		1.20		0.72	20%		1.46		0.29	20%		1.85		0.37	1.38

J. Richard Bird	60%		1.20		0.72	20%		1.47		0.29	20%		1.80		0.36	1.37

Stephen J. Wuori	25%		1.20		0.30	50%		1.31		0.66	25%		1.75		0.44	1.39

David T. Robottom	60%		1.20		0.72	20%		1.46		0.29	20%		1.65		0.33	1.34

Janet Holder	25%		1.20		0.30	50%		1.33		0.67	25%		1.60		0.40	1.37

1: Actual results may vary from mathematical results using our formulas because of rounding.

We used the overall performance multiplier to calculate each named executive's short-term incentive as follows:



	Base salary ($)	×	Short-term incentive target	×	Overall performance multiplier	=	Calculated short-term incentive award1 ($)	Actual short-term incentive award (rounded)2 ($)

Patrick D. Daniel	1,330,000		90%		1.38		1,654,254	1,239,040

Al Monaco	1,000,000		90%		1.38		1,243,800	1,033,550

J. Richard Bird	725,000		65%		1.37		647,498	622,830

Stephen J. Wuori	700,000		65%		1.39		633,588	610,310

David T. Robottom	460,830		50%		1.34		309,217	309,220

Janet Holder	449,400		50%		1.37		306,716	306,730

1: Calculated results may vary from mathematical results due to proration of changes to short-term incentive targets throughout the year. Please see page 49 for more information.
2: Actual results may differ from calculated results due to rounding, and due to proration of changes to short-term incentive targets throughout the year. Please see page 49 for more information.

Medium and Long-term incentives

With the exception of performance stock options which are granted infrequently (usually every five years) in August, our medium and long-term incentives are granted early in the year. Medium and long-term incentives are generally targeted to the 50th percentile of our peer group, with the opportunity to realize this value to a greater or lesser degree based on how Enbridge performs in the future.

Effective January 1, 2012, we granted 128,800 performance stock units to the Enbridge named executives.

In March 2012, we granted 897,100 incentive stock options to the Enbridge named executives. This grant reflected the target delivery for this compensation program and the Black-Scholes value of the stock option at the time of grant. In September 2012, we granted 43,000 incentive stock options to Mr. Bird for retention purposes. Please see page 65 for more information.

In August 2012, we granted 2,910,100 (a 5-year grant covering the period of 2012 - 2016) performance stock options to the Enbridge named executives (excluding Mr. Daniel). This reflected the target delivery for this program and the Black-Scholes value of the stock option at the time of grant. The Black-Scholes option value was discounted by 11.4% to adjust for the additional risk associated with the share price performance hurdles.

Mr. Daniel's long-term incentive target was delivered utilizing incentive stock options and performance stock units to reach the overall long-term incentive target. Mr. Daniel's performance stock unit grant and incentive stock option grants were delivered at 165% of salary versus a target of 115% to reflect his not receiving a performance stock option grant due to his retirement.

2013 Management information circular 60

These grants resulted in annualized total direct compensation (base salary, short-term incentive, medium-term incentive and long-term incentives) being positioned, on average, between the 50th and 75th percentiles of the competitive market.

Performance stock units

The table below shows the performance stock units granted to the named executives in early 2012.



	A Performance stock units granted	B Value ($) (A × CA$36.38)	C Value (%) (B / salary on Dec 31, 2011)

Patrick D. Daniel1	58,000	$2,110,040	165%

Al Monaco	21,200	$771,256	147%

J. Richard Bird	16,100	$585,718	102%

Stephen J. Wuori	16,800	$611,184	101%

David T. Robottom	8,600	$312,868	71%

Janet Holder	8,100	$294,678	70%

1: The HRC Committee approved the full vesting of the performance stock unit grants for Mr. Daniel within the retirement provisions of the plan. Please see page 77 for information on the retirement provisions for share unit plans.

Incentive stock options

The table below shows the incentive stock options granted to the named executives in March 2012 and a grant made to Mr. Bird in September 2012.



	A Incentive stock options granted	B Value ($) (A × CA$5.00)(1)	C Value (%) (B / salary on Dec 31, 2011)

Patrick D. Daniel2	404,300	$2,021,500	158%

Al Monaco	147,500	$737,500	140%

J. Richard Bird	112,300	$561,500	97%

	43,000	$213,710	37%

Stephen J. Wuori	117,300	$586,500	97%

David T. Robottom	59,400	$297,000	67%

Janet Holder	56,300	$281,500	67%

1: The grant of 43,000 options for Mr. Bird was valued at $4.97 at the time of grant in September 2012.
2: The HRC Committee approved a three-year vesting schedule for Mr. Daniel's 2012 incentive stock option grant to allow full vesting within the retirement provisions of the plan. Please see page 77 for information on the retirement provisions for option plans.

Performance stock options

The table below shows the performance stock options granted to the named executives in August 2012.



	Performance stock options granted	Value ($) (A × CA$4.25)1	Value (%) (B / salary on Dec 31, 2012)	Years	Annualized value (%) (C / D)

Al Monaco	1,058,800	$4,499,900	450%	5	90%

J. Richard Bird	591,200	$2,512,600	347%	5	69%

Stephen J. Wuori	617,600	$2,624,800	375%	5	75%

David T. Robottom	325,300	$1,382,525	300%	5	60%

Janet Holder	317,200	$1,348,100	300%	5	60%

1: The values in the above table represent the expected value granted in 2012, valued using the full-term and representing a 5-year period (2012 – 2016).

61 ENBRIDGE INC.

Payouts

The performance stock units granted in 2010 matured on December 31, 2012 and both performance targets were met. The performance multiplier was calculated to be 2.0 based on:



	Target

	0	1.0	2.0	Actual	Performance multiplier

EPS	$1.29	$1.40	$1.57	$1.62	2 × (50% weighting	)

P/E ratio	Below the 50th percentile	Between 50th and 75th percentile	75th percentile and above	91st percentile	2 × (50% weighting	)

The table below shows the performance stock unit payouts to the named executives in early 2013.



	Performance stock units granted in 20101	+	Equivalent to reinvested dividends	=	Total performance stock units	x	Performance multiplier	x	Final share price ($)	=	Payout ($)

Patrick D. Daniel	132,000		12,839		144,839		2.0		41.61		12,053,538

Al Monaco	49,000		4,766		53,766		2.0		41.61		4,474,419

J. Richard Bird	49,000		4,766		53,766		2.0		41.61		4,474,419

Stephen J. Wuori	49,000		4,766		53,766		2.0		41.61		4,474,419

David T. Robottom	33,600		3,268		36,868		2.0		41.61		3,068,173

Janet Holder	6,800		661		7,461		2.0		41.61		620,940

1: The number of units have been adjusted to reflect the Enbridge stock split of May 2011.
2: The HRC Committee approved the full payout of the performance stock unit grant for Mr. Daniel in recognition of his leadership and contribution to the company.

Patrick D. Daniel

(Former) President & Chief Executive Officer

Total direct compensation


	20121			2011	2010

	$	%		$	$

Cash
Base salary	976,224	(23.1%	)	1,269,750	1,231,500
Short-term incentive	1,239,040	(48.3%	)	2,396,000	1,290,000
	$2,215,264	(39.6%	)	$3,665,750	$2,521,500
Equity

Performance stock units	2,110,040	47.6%		1,429,504	3,117,180
Incentive stock options	2,021,500	38.1%		1,464,000	1,322,020
	$4,131,540	42.8%		$2,893,504	$4,439,200

1: The numbers in this table reflect actual earnings. Mr. Daniel retired on September 30, 2012.

Base salary

Effective April 1, 2012, Mr. Daniel's base salary was increased by 4% to maintain his competitive market positioning.

Short-term incentive

A portion of Mr. Daniel's short-term incentive award is based on company performance (60%), measured in 2012 by adjusted EPS. Corporate performance on this measure was 1.20 out of 2.0 (see page 58). The corporate performance multiplier reflects the discretion applied by the HRC Committee outlined on page 58.

Operational business unit performance across the enterprise accounts for 20% of Mr. Daniel's short-term incentive award calculation, with individual performance accounting for the remaining 20%.

Operational business unit performance includes safety, system reliability, environmental performance and other non-financial metrics. Business unit performance in 2012 was 1.46 out of 2.0.

2013 Management information circular 62

Individual performance is assessed relative to the achievement of individual objectives established at the beginning of the year tied to operational and strategic priorities.

Upon providing formal notice to the Board of Directors of his intent to retire at some in 2012, Mr. Daniel worked with the Board and the chair of the HRC Committee to finalize succession plans and determine an appropriate and comprehensive transition strategy. The focus for Mr. Daniel for the balance of the year until his retirement date September 30, 2012 was to ensure the successful execution of the transition plan. This was done very successfully such that:

•: the company's valuation did not come under pressure and there was a positive reception to the new Chief Executive Officer by the investment community;
•: numerous meetings were held with all stakeholders including shareholders, analysts, customers, regulators, government officials and employees;
•: a third party independent survey of Enbridge Days investors presentations revealed strong results in all areas and confirmed the goal of continuity with investors was achieved; and
•: positive feedback and market reaction to stakeholder meetings, media interviews and government meetings.

In addition, Mr. Daniel provided strong support for the successful business development activities of the company to secure $14 billion in new investments.

The Board acknowledged Mr. Daniel's strong performance and continued leadership in 2012 and his individual performance multiplier was approved at 1.85 out of 2.0.

Mr. Daniel's combined 2012 incentive award was $1,239,040.

Medium and long-term incentives

Mr. Daniel was awarded 404,300 incentive stock options and 58,000 performance stock units in March 2012.

Al Monaco

(Current) President & Chief Executive Officer

Total direct compensation


	2012		2011	2010

	$	%	$	$

Cash
Base salary	804,167	55.0%	518,750	487,500
Short-term incentive	1,033,550	103.7%	507,490	344,000
	$1,837,717	79.1%	$1,026,240	$831,500
Equity

Performance stock units	771,256	97.3%	390,880	1,157,135
Incentive stock options	737,500	84.4%	400,000	372,400
Performance stock options	4,499,900	–	–	–
	$6,008,656	659.7%	$790,880	$1,529,535

Base salary

Effective February 27, 2012, Mr. Monaco's base salary was increased by 52% to reflect his promotion to President. On October 1, 2012 Mr. Monaco was appointed President & Chief Executive Officer, and his base salary was increased by an additional 25%.

Short-term incentive

A portion of Mr. Monaco's short-term incentive award is based on company performance (60%), measured in 2012 by adjusted EPS. Corporate performance on this measure was 1.20 out of 2.0 (see page 58). The corporate performance multiplier reflects the discretion applied by the HRC Committee outlined on page 58.

Operational business unit performance across the enterprise accounts for 20% of Mr. Monaco's short-term incentive award calculation, with individual performance accounting for the remaining 20%.

63 ENBRIDGE INC.

Operational business unit performance includes safety, system reliability, environmental performance and other non-financial metrics. Business unit performance in 2012 was 1.46 out of 2.0.

Individual performance is assessed relative to the achievement of individual objectives established at the time Mr. Monaco became President, then again when he became President & Chief Executive Officer, related to operational and strategic priorities.

In 2012, Mr. Monaco:

•: oversaw execution of the other key priorities and success factors to support the company's strategic plan in the following areas:
•  delivered Enbridge's major capital projects on time and on budget;
•  ensured the necessary human resources to execute the capital program through the hiring of a record number of permanent and contract staff;
•  ensured cost effective funding and liquids to support the current and future secured capital program through extensive capital markets and bank credit activity;
•: oversaw securement of the company's largest ever slate of new investments totaling $14 billion corporate-wide;
•: achieved strong financial results, generating 2012 adjusted EPS growth of 11% over 2011 and reflecting top-quartile performance among our peer group;
•: generated top-decile total shareholder return of 16.2%;
•: maintained Enbridge's premium equity valuation relative to its' peer group;
•: completed objectives outlined in the company's ORM Plan, thereby establishing a path to attainment of industry leadership in key safety and operational areas;
•: directed further enhancement of the company's ORM Plan geared to further enhancing and promoting a culture of safety (public, personal and process), operational reliability and environmental performance;
•: chaired the Operations and Integrity Committee, comprised of the Executive Leadership Team and the most senior Operations and Engineering representatives from across the enterprise;
•: enhanced relationships with customers and developed new partnerships with industry peers; and
•: maintained business continuity and Enbridge's position in the capital markets as part of the Chief Executive Officer transition, which included establishing the company's key priorities over the next five years.

The Board acknowledged Mr. Monaco's strong performance and leadership in 2012 and his individual performance multiplier was approved at 1.85 out of 2.0.

Mr. Monaco's combined 2012 short-term incentive award was $1,033,550.

Medium and long-term incentives

Mr. Monaco was awarded 147,500 incentive stock options and 21,200 performance stock units in March 2012, and 1,058,800 performance stock options in August 2012.

J. Richard Bird

Executive Vice President, Chief Financial Officer & Corporate Development

Total direct compensation


	2012		2011	2010

	$	%	$	$

Cash
Base salary	700,300	22.3%	572,600	555,000
Short-term incentive	622,830	5.1%	592,620	362,000
	$1,323,130	13.6%	$1,165,220	$917,000
Equity

Performance stock units	585,718	49.8%	390,880	1,157,135
Incentive stock options	775,210	93.8%	400,000	372,400
Performance stock options	2,512,600	–	–	–
	$3,873,528	389.8%	$790,880	$1,529,535

2013 Management information circular 64

Base salary

Effective March 1, 2012, Mr. Bird's base salary was increased by 25.7%, to reflect an increase in his portfolio of responsibilities.

Short-term incentive

A portion of Mr. Bird's short-term incentive award is based on company performance (60%), measured in 2012 by adjusted EPS. Corporate performance on this measure was 1.20 out of 2.0 (see page 58). The corporate performance multiplier reflects the discretion applied by the HRC Committee outlined on page 58.

Business unit performance accounts for 20% of Mr. Bird's short-term incentive award calculation. The business unit component for Corporate employees is based on a combination of several metrics. Operational performance across the enterprise includes metrics related to safety, system reliability, and environmental performance, cost containment which reinforces accountability for managing controllable costs and employee retention which measures the ability to retain key talent and critical skills. Corporate business unit performance in 2012 was 1.46 out of 2.0. Mr. Bird also has accountability for the Green Energy, International and Energy Marketing groups within Enbridge, which had an aggregated business unit performance multiplier of 1.5 out of 2.0. Mr. Bird's business unit component is calculated from both Corporate business unit performance (80%) and the Green Energy, International and Energy Marketing performance (20%). Mr. Bird's overall business unit multiplier was 1.47 out of 2.0.

The remaining 20% of Mr. Bird's incentive award is based on individual performance which is assessed relative to the achievement of individual objectives established at the beginning of the year tied to operational and strategic priorities.

In 2012, Mr. Bird:

•: successfully issued, on favourable terms, $2.2 billion of enterprise-wide term debt, $400 million of Enbridge common equity, $200 million of equity for Enbridge Income Fund Holdings Inc., $400 million of equity for Enbridge Energy Partners, L.P., $2.7 billion of Enbridge preferred shares, and added $4.6 billion of additional bank credit facilities. These transactions included a significant level of equity and debt prefunding in support of Enbridge's $35 billion five year growth capital plan;
•: completed the Eastern Access and Mainline Expansion joint funding arrangements between Enbridge and Enbridge Energy Partners, L.P. to facilitate the financing of significant Liquids Pipelines growth investments;
•: completed a $1.2 billion drop down of assets to Enbridge Income Fund, significantly enhancing Enbridge's return on the assets;
•: oversaw successful growth initiatives for Enbridge's renewable energy, energy services and new technologies businesses; and
•: provided commercial structuring support, risk/return guidance, financial analysis and investment review for $14 billion of capital investment opportunities secured by the various business units.

Mr. Bird's individual performance multiplier was approved at 1.80 out of 2.0.

Mr. Bird's combined 2012 short-term incentive award was $622,830.

Medium and long-term incentives

Mr. Bird was awarded 112,300 incentive stock options and 16,100 performance stock units in March 2012, and 591,200 performance stock options in August 2012.

With the Chief Executive Officer transition experienced in 2012, Mr. Bird was asked to commit to an additional two years of service to maintain executive leadership team stability and continuity. For this commitment, the company has agreed to provide him with a retention payment of $1.3 million effective April 2014 and, in September 2012, Mr. Bird was awarded 43,000 incentive stock options.

65 ENBRIDGE INC.

Stephen J. Wuori

President, Liquids Pipelines & Major Projects

Total direct compensation


	2012			2011	2010

	$	%		$	$

Cash
Base salary	684,247	14.0%		600,360	580,500
Short-term incentive	610,310	(2.4%	)	625,240	343,000
	$1,294,557	5.6%		$1,225,600	$923,500
Equity

Performance stock units	611,184	56.4%		390,880	1,157,135
Incentive stock options	586,500	46.6%		400,000	372,400
Performance stock options	2,624,800	–		–	–
	$3,822,484	383.3%		$790,880	$1,529,535

Base salary

Effective March 1, 2012, Mr. Wuori's base salary was increased by 16%, to reflect an increase in his portfolio of responsibilities.

Short-term incentive

Mr. Wuori's short-term incentive award is based on company performance (25%), measured in 2012 by adjusted EPS. Corporate performance on this measure was determined to be 1.20 out of 2.0 (see page 58). The corporate performance multiplier reflects the discretion applied by the HRC Committee outlined on page 58.

Business unit performance accounts for 50% of Mr. Wuori's short-term incentive award calculation. 80% of Mr. Wuori's business unit component is calculated from the performance of Liquids Pipelines, while 20% is calculated from the performance of Major Projects, which is also under his direction. Financial performance, measured by earnings relative to the approved 2012 budget, was slightly below target for Liquids Pipelines. Safety and environmental performance indicators as well as pipeline integrity results were above target and secured business development was well above target. Workforce metrics (measured by employee turnover and hiring metrics) were also well above target. The business unit multiplier for Liquids Pipelines was 1.27 out of 2.0. The performance of Major Projects was also above target on all metrics, including schedule, cost, quality, environmental compliance, safety and workforce metrics. The business unit multiplier for Major Projects was 1.53 out of 2.0. Mr. Wuori's overall business unit multiplier was 1.31 out of 2.0.

The remaining 25% of Mr. Wuori's short-term incentive award is based on individual performance which is assessed relative to the achievement of individual objectives established at the beginning of the year tied to operational and strategic priorities.

In 2012, Mr. Wuori:

•: fostered Safety Culture Enhancement initiatives across Liquids Pipelines and achieved a record of no fatalities or significant injuries across the workforce;
•: presided over the largest pipeline integrity management program in the company's history;
•: secured over $9 billion in new growth projects through extensive business development activities across North America;
•: provided leadership in the remaining activities on the Kalamazoo River cleanup from the 2010 spill. The river was fully reopened for public usage in June 2012;
•: maintained extensive involvement in pipeline regulatory and public issues through involvement on the Boards of US and Canadian industry associations; and
•: provided support to the outgoing and incoming Chief Executive Officers through the transition in 2012.

Mr. Wuori's individual performance multiplier was approved at 1.75 out of 2.0.

Mr. Wuori's combined 2012 short-term incentive award was $610,310.

2013 Management information circular 66

Medium and Long-term incentives

Mr. Wuori was awarded 117,300 incentive stock options and 16,800 performance stock units in March 2012, and 617,600 performance stock options in August 2012.

David T. Robottom

Executive Vice President & Chief Legal Officer

Total direct compensation


	2012			2011	2010

	$	%		$	$

Cash
Base salary	456,398	4.2%		437,825	414,500
Short-term incentive	309,220	(31.3%	)	450,380	276,000
	$765,618	(13.8%	)	$888,205	$690,500
Equity

Performance stock units	312,868	5.7%		295,952	793,464
Incentive stock options	297,000	(2.0%	)	303,200	265,335
Performance stock options	1,382,525	–		–	–
	$1,992,393	232.5%		$599,152	$1,058,799

Base salary

Effective April 1, 2012, Mr. Robottom's base salary was increased by 4% to maintain overall market competitiveness.

Short-term incentive

A portion of Mr. Robottom's short-term incentive award is based on company performance (60%), measured in 2012 by adjusted EPS. Corporate performance on this measure was determined to be 1.20 out of 2.0 (see page 58). The corporate performance multiplier reflects the discretion applied by the HRC Committee outlined on page 58.

The business unit component for Corporate employees is based on a combination of several metrics. Operational performance across the enterprise includes metrics related to safety, system reliability and environmental performance, cost containment (which reinforces accountability for managing controllable costs) and employee retention (which measures the ability to retain key talent and critical skills). Business unit performance in 2012 was 1.46 out of 2.0, accounting for 20% of Mr. Robottom's 2012 short-term incentive award.

The remaining 20% of Mr. Robottom's short-term incentive award is based on individual performance which is assessed relative to the achievement of individual objectives established at the beginning of the year tied to operational and strategic priorities.

In 2012, Mr. Robottom:

•: oversaw several successful phases and, in some cases, conclusions of numerous significant legal matters, including progressing a defense through favourable appellate decisions in an action which has been ongoing (notwithstanding an original dismissal of the plaintiff's claim), numerous significant regulatory approvals for large developmental projects which were or are being opposed by various special interest groups, various regulatory reviews and completion of several substantial new commercial and joint venture arrangements, as well as asset acquisitions and dispositions and roughly $10 billion in financing transactions;
•: achieved a large majority of stated 2012 objectives, including milestones in integration of IT functions enterprise-wide, changes in the IT structure, successful roll out of the IT components of a new compensation process and restructuring the enterprise legal compliance function and related policies and procedures;
•: achieved 2012 objectives for records management functions, including the roll out to Corporate and Liquids Pipelines divisions of a complex email management program (which is being rolled out across the balance of the enterprise in 2013); and
•: oversaw significant advancement in a number of other large IT projects, including risk management assessment and mitigation goals in IT security, while also improving cost efficiencies in both IT and records management.

67 ENBRIDGE INC.

Mr. Robottom's individual performance multiplier was approved at 1.65 out of 2.0.

Mr. Robottom's combined 2012 short-term incentive award was $309,220.

Medium and long-term incentives

Mr. Robottom was awarded 59,400 incentive stock options and 8,600 performance stock units in March 2012, and 325,300 performance options in August 2012.

Janet Holder

Executive Vice President, Western Access

Total direct compensation


	2012			2011	2010

	$	%		$	$

Cash
Base salary	442,050	6.5%		415,000	340,975
Short-term incentive	306,730	(12.3%	)	349,580	244,000
	$748,780	(2.1%	)	$764,580	$584,975
Equity

Performance stock units	294,678	(12.0%	)	335,040	160,582
Incentive stock options	281,500	(12.0%	)	320,000	636,172
Performance stock options	1,348,100	–		–	–
	$1,924,278	193.8%		$655,040	$796,754

Base salary

Effective April 1, 2012, Ms. Holder's base salary was increased by 7% to better align her positioning to the competitive market.

Short-term incentive

A portion of Ms. Holder's short-term incentive award is based on company performance (25%), measured in 2012 by adjusted EPS. Corporate performance on this measure was determined to be 1.20 out of 2.0 (see page 58). The corporate performance multiplier reflects the discretion applied by the HRC Committee outlined on page 58.

50% of Ms. Holder's short-term incentive award is based on metrics related to the Western Access project. Financial performance, measured by budget spent relative to the approved 2012 budget was at target. Business development initiatives were also at target. Regulatory metrics were above target, as were the number of First Nations signed agreements. The remaining elements came in at target. Ms. Holder's business unit multiplier was determined to be 1.33 out of 2.0.

The remaining 25% of Ms. Holder's short-term incentive award is based on individual performance which is assessed relative to the achievement of individual objectives established at the beginning of the year tied to operational and strategic priorities.

In 2012, Ms. Holder:

•: provided a thorough and extensive record to the Joint Review Panel in support of the Northern Gateway project. This included timely responses to intervenor questions through the filing of several technical reports. The evidence was substantiated through effective oral evidence by Northern Gateway's witnesses;
•: received a positive TERMPOL Report from Transport Canada, which states that while there will always be residual risks in any project, after reviewing the Northern Gateway studies and commitments, there are no regulatory concerns identified for the vessels, route or marine terminal operation;
•: oversaw extensive engagement with Aboriginal Communities within the Northern Gateway project. Of 45 Aboriginal groups eligible for an equity interest in the pipeline, 60% signed equity agreements. Agreements are also in place with some groups regarding skills development; and
•: implemented a number of initiatives to increase the awareness of Northern Gateway's commitment to safety and the environment.

2013 Management information circular 68

Ms. Holder's individual performance multiplier was approved at 1.60 out of 2.0.

Ms. Holder's combined 2012 short-term incentive award was $306,730.

Medium and long-term incentives

Ms. Holder was awarded 56,300 incentive stock options and 8,100 performance stock units in March 2012, and 317,200 performance options in August 2012.

Executive compensation and shareholder return

The chart below shows what $100 invested in Enbridge shares on December 31, 2007 would have been worth at the end of each of the last five years (assuming reinvestment of dividends) and compares that to the performance of the S&P/TSX Composite Index. It also shows total compensation reported for the named executives each year.

We grant performance stock options approximately every five years. The awards in 2012 increased total compensation significantly because we included the full grant date fair value of the stock options in the year's compensation.

Total return vs. total compensation


	As at December 31	2008 ($)	2009 ($)	2010 ($)	2011 ($)	2012 ($)

Enbridge Total Return		$102	$130	$156	$218	$253

S&P/TSX Composite Total Return Index		$67	$90	$106	$97	$104

Total compensation of named executives ($MM)1		$16.0	$14.1	$18.1	$16.3	$40.5

1: Includes total compensation disclosed in previous management information circulars for the named executive officers in those years. Total compensation includes base salary, short-term and longer-term incentives (grant date fair value), annual pension value and all other compensation.

69 ENBRIDGE INC.

2012 RESULTS

Summary compensation table

The table below shows the total we and our subsidiaries paid and granted to the named executives for the years ended December 31, 2012, 2011 and 2010.


	Executive and principal position	Year	Salary ($)	Share- based awards1 ($)	Option- based awards2 ($)	Non-equity (annual incentive plan)3 ($)	Pension value4 ($)	All other compensation5 ($)	Total compensation ($)

Patrick D. Daniel6		2012	976,224	2,110,040	2,021,500	1,239,040	1,567,000	139,515	8,053,319
(Former) President & Chief		2011	1,269,750	1,429,504	1,464,000	2,396,000	862,000	200,513	7,621,767
Executive Officer		2010	1,231,500	3,117,180	1,322,020	1,290,000	949,000	146,156	8,055,856

Al Monaco		2012	804,167	771,256	5,237,400	1,033,550	4,251,000	69,099	12,166,472
President & Chief		2011	518,750	390,880	400,000	507,490	221,000	49,975	2,088,095
Executive Officer		2010	487,500	1,157,135	372,400	344,000	238,000	49,944	2,648,979

J. Richard Bird		2012	700,300	585,718	3,287,810	622,830	1,596,000	68,535	6,861,193
Executive Vice President,		2011	572,600	390,880	400,000	592,620	300,000	64,821	2,320,921
Chief Financial Officer &		2010	555,000	1,157,135	372,400	362,000	192,000	64,776	2,703,311
Corporate Development

Stephen J. Wuori		2012	684,247	611,184	3,211,300	610,310	1,998,000	71,143	7,186,184
President, Liquids Pipelines		2011	600,360	390,880	400,000	625,240	213,000	202,007	2,431,487
& Major Projects		2010	578,223	1,157,135	372,400	343,000	134,000	68,598	2,653,356

David T. Robottom		2012	456,398	312,868	1,679,525	309,220	434,000	44,453	3,236,464
Executive Vice President &		2011	437,825	295,952	303,200	450,380	317,000	44,126	1,848,483
Chief Legal Officer		2010	414,500	793,464	265,335	276,000	269,000	43,807	2,062,106

Janet Holder		2012	442,050	294,678	1,629,600	306,730	268,000	51,308	2,992,366
Executive Vice President,		2011	415,000	335,040	320,000	349,580	660,000	91,054	2,170,674
Western Access		2010	340,975	160,582	636,172	244,000	69,000	41,541	1,492,270

1: Performance stock unit plan (see page 61).
Performance stock units granted × unit value, using the following unit values:


	Year	CA$	US$	Exchange rate US$1=$CA

2012		36.38	–	–
2011		27.92	–	–
2010		47.23	44.93	1.0466
2009		38.71	31.40	1.2246

The unit value is the volume weighted average of an Enbridge share on the TSX or the NYSE for the last 20 trading days before the grant date. It takes into account the notional dividends that are reinvested during the performance period. For compensation reporting, we use the grant date fair value. This is different from the accounting value, which is based on a mark-to-market valuation of an Enbridge share at the end of each financial quarter, including notional dividends accrued. 2011 unit value reflects 2-1 stock split.

2: Performance stock option plan (see page 61)
Performance stock options are granted approximately once every five years. Performance stock options granted × stock option value, using the following stock option values:


		2012

	Assumptions	Grant date fair value and accounting value

Expected option term in years		8
Expected volatility		16.10%

Expected dividend yield		2.80%
Risk free interest rate		1.60%

Exercise price		$39.34
Performance discount		11.4%
Performance option value		$4.25

We use the Black-Scholes method to determine the performance stock option value and discount it, using a Monte Carlo simulation to reflect the Enbridge share price targets that must be met for the performance stock options to vest. We granted all performance stock options in CA$. The above values have been adjusted.
Stock option plans (see page 61)
In 2010, the grant date fair value is different from the accounting value. The HRC Committee chose to continue to use two year historical volatility

2013 Management information circular 70

assumptions for the grant date fair value. In 2010, given the extreme volatility in equity markets over the prior two years, Enbridge did not believe that a two year estimate was a more accurate reflection of the forward volatility of Enbridge shares over the period that the options are expected to be outstanding. The grant date accounting value uses six year historical volatility and six month forward implied volatility.


		March 2012	February 2011	February 2010

	Assumptions	Grant date fair value and accounting value	Grant date fair value and accounting value	Grant date fair value	Grant date accounting value

Expected option term in years		6	6	6	6

Expected volatility		19.00%	17.80%	26.60%	19.10%
Expected dividend yield		2.95%	3.41%	3.64%	3.64%

Risk free interest rate		1.45%	2.88%	2.65%	2.65%
Exercise price		$38.34	$28.78	$23.30	$23.30

Regular option value		$5.00	$4.00	$4.66	$3.28

3: Non-equity (annual incentive plan) (see page 60)
Amounts in this column reflect the short-term incentive plan awards earned in 2012 and payable on February 28, 2013. Awards are based on Enbridge, business unit and individual performance. Particulars on the short-term incentive awards calculations for each named executive are set forth on page 60 of this circular. There are no long-term non-equity incentive plans within the compensation programs.
4: Retirement benefits (see page 75)
The pension values are equal to the compensatory change shown in the defined benefit plan and defined contribution plan tables.
5: Other benefits (see page 54)
Amounts in this column include the annual perquisite allowance, excess flexible benefit credits paid to the executive, the taxable benefit from loans by Enbridge (made before Sarbanes-Oxley was enacted), parking, relocation subsidies, medical expenses, financial counseling benefits and other incidental compensation. Mr. Daniel's and Mr. Wuori's other compensation includes an air travel benefit. For Mr. Daniel, that benefit was $23,625 in 2012, $81,514 in 2011 and $27,256 in 2010. For Mr. Wuori, that benefit was $0 in 2012, $41,704 in 2011 and $0 in 2010.


	Perquisite Allowance	Financial planning reimbursement

Patrick D. Daniel	$49,500	50% up to $10,000
Al Monaco *	$34,875	50% up to $10,000
J. Richard Bird	$35,000	50% up to $5,000
Stephen J. Wuori	$35,000	50% up to $5,000
David T. Robottom	$30,000	50% up to $5,000
Janet Holder	$35,000	50% up to $5,000

*: Mr. Monaco's perquisite allowance was prorated for 2012 with an adjustment to his annual allowance of $30,000 (from January to September) to $49,500 (from October to December).
6: The numbers in this table reflect actual earnings. Mr. Daniel retired on September 30, 2012.

Incentive plan awards

Outstanding option-based and share-based awards as of December 31, 2012



		Option-based awards					Share-based awards

	Executive	Number of securities underlying unexercised options1 (#)	Option exercise price1 ($)	Option expiration date	Value of unexercised in-the-money options1,2 ($)		Number of units that have not vested (#)	Unit maturity date	Market or payout value of units not vested3,4 ($)	Market or payout value of vested share-based awards not paid out or distributed5 ($)

					Vested	Unvested
Patrick D. Daniel		404,300	38.34	2-Mar-22	–	1,892,124	59,679	31-Dec-14	1,604,631	12,053,538
		366,000	28.78	14-Feb-21	1,303,418	3,910,253	54,322	31-Dec-13	1,460,574
		284,000	23.30	16-Feb-20	2,800,950	2,800,950
		424,000	19.81	25-Feb-19	7,382,370	2,460,790
		424,000	20.21	19-Feb-18	9,671,440	–
		298,000	19.13	9-Feb-17	7,119,220	–
		1,560,998	18.29	15-Aug-15	38,611,286	–

71 ENBRIDGE INC.



		Option-based awards					Share-based awards

	Executive	Number of securities underlying unexercised options1 (#)	Option exercise price1 ($)	Option expiration date	Value of unexercised in-the-money options1,2 ($)		Number of units that have not vested (#)	Unit maturity date	Market or payout value of units not vested3,4 ($)	Market or payout value of vested share-based awards not paid out or distributed5 ($)

					Vested	Unvested
Al Monaco		147,500	38.34	2-Mar-22	–	690,300	21,814	31-Dec-14	586,520	4,474,419
		100,000	28.78	14-Feb-21	356,125	1,068,375	14,854	31-Dec-13	399,376
		1,058,800	39.34	15-Aug-20	–	3,896,384
		80,000	23.30	16-Feb-20	789,000	789,000
		100,000	19.81	25-Feb-19	1,741,125	580,375
		90,000	20.21	19-Feb-18	2,052,900	–
		28,400	19.13	9-Feb-17	678,476	–
		32,600	18.24	13-Feb-16	807,991	–
		500,000	20.21	15-Aug-15	9,124,000	2,281,000
		37,600	15.84	3-Feb-15	1,021,968	–
		54,800	12.86	4-Feb-14	1,652,768	–

J. Richard Bird		43,000	38.32	28-Sep-22	–	202,100	16,566	31-Dec-14	445,423	4,474,419
		112,300	38.34	2-Mar-22	–	525,564	14,854	31-Dec-13	399,376
		100,000	28.78	14-Feb-21	356,125	1,068,375
		591,200	39.34	15-Aug-20	–	2,175,616
		80,000	23.30	16-Feb-20	789,000	789,000
		120,000	19.81	25-Feb-19	2,089,350	696,450
		120,000	20.21	19-Feb-18	2,737,200	–
		90,000	19.13	9-Feb-17	2,150,100	–
		96,600	18.24	13-Feb-16	2,394,231	–
		440,000	18.29	15-Aug-15	10,883,400	–

Stephen J. Wuori		117,300	38.34	2-Mar-22	–	548,964	17,286	31-Dec-14	464,790	4,474,419
		100,000	28.78	14-Feb-21	356,125	1,068,375	14,854	31-Dec-13	399,376
		617,600	39.34	15-Aug-20	–	2,272,768
		80,000	23.30	16-Feb-20	789,000	789,000
		120,000	19.81	25-Feb-19	2,089,350	696,450
		120,000	20.21	19-Feb-18	2,737,200	–
		90,000	19.13	9-Feb-17	2,150,100	–
		96,600	18.24	13-Feb-16	2,394,231	–
		660,000	18.29	15-Aug-15	16,325,100	–
		91,600	15.84	3-Feb-15	2,489,688	–
		78,000	12.86	4-Feb-14	2,352,480	–

David T. Robottom		59,400	38.34	2-Mar-22	–	277,992	8,849	31-Dec-14	237,928	3,068,173
		75,800	28.78	14-Feb-21	269,943	809,828	11,246	31-Dec-13	302,384
		325,300	39.34	15-Aug-20	–	1,197,104
		57,000	23.30	16-Feb-20	562,163	562,163
		70,000	19.81	25-Feb-19	1,218,788	406,263
		70,000	20.21	19-Feb-18	1,596,700	–
		46,800	17.28	1-Jun-16	1,204,866	–

Janet Holder		56,300	38.34	2-Mar-22	–	263,484	8,335	31-Dec-14	224,095	620,940
		80,000	28.78	14-Feb-21	284,900	854,700	12,732	31-Dec-13	342,322
		92,000	27.84	12-Nov-20	698,280	698,280
		317,200	39.34	15-Aug-20	–	1,167,296
		58,400	23.30	16-Feb-20	575,970	575,970
		66,400	19.81	25-Feb-19	1,156,107	385,369
		52,600	20.21	19-Feb-18	1,199,806	–
		19,200	19.13	9-Feb-17	458,688	–
		22,800	18.24	13-Feb-16	565,098	–
		24,800	15.84	3-Feb-15	674,064	–
		47,200	12.86	4-Feb-14	1,423,552	–

1: Calculated using the Enbridge share close price on December 31, 2012: CA$43.02, and where applicable, the number of the number of options or units and the option exercise prices (as listed on the TSX) have been adjusted to reflect the Enbridge stock split of May 2011.
2: Incentive stock options are subject to time vesting conditions. Performance stock options are subject to time and performance vesting conditions. See page 50 for details.
3: We calculated the market value of performance stock units that have not vested using the formula on page 62 and the Enbridge share price on December 31, 2012: CA$43.02.
4: We have assumed a threshold performance multiplier of 0.625, based on meeting the minimum EPS threshold (50%) and a relative P/E ratio ranking of at least the 50th percentile. See page 62 for details.
5: This is a reflection of the estimated payout value of the 2010 Performance Stock Unit Grant, which vested on December 31, 2012 but will not be paid out until approximately March 2013. We have assumed a performance multiplier of 2.0.

2013 Management information circular 72

Value vested or earned in 2012


Executive	Option-based awards – value vested during the year ($)	Share-based awards – value vested during the year1 ($)	Non-equity incentive plan compensation – value earned during the year2 ($)

Patrick D. Daniel	14,361,343	12,053,538	1,239,040

Al Monaco	3,169,175	4,474,419	1,033,550

J. Richard Bird	4,451,895	4,474,419	622,830

Stephen J. Wuori	4,451,895	4,474,419	610,310

David T. Robottom	2,577,188	3,068,173	309,220

Janet Holder	1,237,712	620,940	306,730

1: The performance stock units granted in 2010 matured on December 31, 2012. See page 62 for details.
2: Based on corporate and business unit performance at an "exceeds" rating and varying individual performance. See page 60 for details.

The value of the option-based awards is based on the following:


Grant date	Grant price	2012 vesting date	Closing Price on 2012 vesting date

14-Feb-2011	$28.775	14-Feb-2012	$39.10

16-Feb-2010	$23.295	16-Feb-2012	$39.20

19-Feb-2008	$20.210	19-Feb-2012	$37.58

25-Feb-2009	$19.805	25-Feb-2012	$38.41

25-Feb-2009	$19.710	15-Jun-2012	$39.38

15-Aug-2007	$18.285	15-Aug-2012	$39.47

02-Sep-2011	$32.020	02-Sep-2012	$38.81

12-Nov-2010	$27.840	12-Nov-2012	$39.22

Enbridge shares used for purposes of equity compensation

We currently grant stock options under our stock options plans, which were approved by shareholders in 2007:

•: the incentive stock option plan (2007), as amended and restated (2011)
•: the performance stock option plan (2007), as amended and restated (2011) and as further amended (2012).

Please see page 52 for further information regarding our stock option plans.

Before these plans were approved, we issued incentive stock options and performance stock options under our legacy incentive stock option plan (2002) (legacy stock option plan). While we no longer grant options under the legacy incentive stock option plan, there are still some options outstanding.

Enbridge common shares reserved for equity compensation as of December 31, 2012:


	Plan	Number of securities to be issued upon exercise of outstanding options, warrants and rights (#) (a)	Weighted-average exercise price of outstanding options, warrants and rights ($) (b)	Number of securities remaining available for future issue under equity compensation plans (excluding securities reflected in column (a)) (#) (c)

Stock option plans		29,951,331	27.76	18,529,024

Legacy stock option plan		4,120,510	16.92	–

73 ENBRIDGE INC.

Plan restrictions


Enbridge common shares we can reserve for issue under all stock option plans		• 52,000,000 in total, or 6.4% of our total issued and outstanding Enbridge common shares as of March 5, 2013 • for an employee – no more than 5% of the total Enbridge common shares issued and outstanding; and • for insiders – no more than 10% of the total Enbridge common shares issued and outstanding.

Enbridge common shares that can be issued in a one-year period		• For an insider or his or her associate – no more than 5% of the total Enbridge common shares issued and outstanding • for insiders as a group – no more than 10% of the total Enbridge common shares issued and outstanding.

The number of Enbridge common shares that can be issued as incentive stock options (within the meaning of the US Internal Revenue Code) to designated employees of our US subsidiaries		• Up to 2,000,000 Enbridge common shares can be issued to these employees under each stock option plan unless, at the time of the grant: • the employee owns Enbridge common shares that give him or her more than 10% of the total combined voting power of all classes of shares in his or her employer or of its parent or subsidiary, unless the grant price is at least 110% of the fair market value of the shares and the options are to be exercised within five years of the grant date; or • the employee has options that can be exercised in a single calendar year for Enbridge common shares that have a total fair market value of more than US$100,000 (or the amount set out in the US Internal Revenue Code).

Options the Chief Executive Officer can grant to new executives when they join the company		Up to 2% of the total Enbridge common shares outstanding at the time of the grant (undiluted) or the amount stated in the policies of the HRC Committee (whichever is less).

Termination provisions

The termination provisions for the stock option plans are summarized below. Performance stock options have the same termination provisions as incentive stock options except:

•: for retirement, we prorate their performance stock options for the period of active employment in the 5 year period starting January 1 of the year of grant. They can exercise these options until the later of three years after retirement or 30 days after the share price targets must be met (or up to the date the option expires, whichever is earlier), as long as the performance criteria are met;
•: for death, unvested options are pro-rated and the plan assumes performance requirements have been met;
•: for involuntary termination (not for cause), unvested options are pro-rated; and
•: for change of control, the plan assumes the performance requirements have been met.

We pro-rate based on active employment during the vesting period (any notice period for an involuntary not for cause termination is included as active employment) and we treat the pro-rated options as time vested.


Reason for termination		Provision

Resignation		Can exercise vested options up to 30 days from the date of termination or until the option term expires (whichever is sooner).

Retirement		Incentive stock options continue to vest. Vested options can be exercised up to three years from retirement or until the stock option term expires (whichever is sooner). Conditions for Performance stock options are mentioned above.

Death		All options vest and can be exercised up to 12 months from the date of death or until the option term expires (whichever is sooner).

Disability		Stock option plans: Options continue to vest based on the regular provisions of the plan.
		Legacy stock option plan: Options continue to vest. Vested options can be exercised up to three years from the date of disability or until the option term expires (whichever is sooner).

Termination – involuntary, not for cause		Stock option plans: Unvested options continue to vest and vested options can be exercised up to 30 days after the notice period expires or until the option term expires (whichever is sooner). Legacy stock option plan: Can exercise vested options up to 30 days from the date of termination or until the option term expires (whichever is sooner).

2013 Management information circular 74

– involuntary, for cause		Stock option plans: All options are cancelled on the date of termination. Legacy stock option plan: Can exercise vested options up to 30 days from the date of termination or until the option term expires (whichever is sooner).

– change of control or reorganization		Stock option plans: For a change of control, options vest on a date determined by the HRC Committee before the change of control. For any other kind of reorganization, options are to be assumed by the successor company. If they are not assumed, they will vest and the value will be paid in cash. Legacy stock option plan: Options will be assumed by the successor company. If they are not assumed, they will vest and the value will be paid in cash.

Copies of our stock option plans are available on SEDAR (www.sedar.com).

Retirement plan benefits

Defined Benefit Plans

The following table outlines estimated annual retirement benefits, accrued pension obligations and compensatory and non-compensatory changes for the named executives under the defined benefit pension plans. All information is based on the assumptions and methods used for the purposes of reporting the company's financial statements and which are described in the company's financial statements.


		Annual benefits payable		Accrued obligation at start of	Compensatory	Non- compensatory		Accrued obligation
	Number of years of credited service	At year end ($)	At age 65 ($)	year ($)	change1 ($)	change2 ($)		at year end ($)

Patrick D. Daniel3	36.5	1,604,000	1,604,000	23,373,000	1,567,000	(69,000	)	24,871,000

Al Monaco4	14.08	248,000	781,000	2,813,000	4,251,000	650,000		7,714,000

J. Richard Bird5	17.92	431,000	493,000	5,795,000	1,596,000	299,000		7,690,000

Stephen J. Wuori	32.56	519,000	784,000	7,898,000	1,998,000	799,000		10,695,000

David T. Robottom6	6.58	167,000	284,000	2,049,000	434,000	187,000		2,670,000

Janet Holder7	18.33	192,000	312,000	2,867,000	268,000	317,000		3,452,000

1: The compensatory change includes current service cost, special arrangements and the difference between actual and estimated earnings.
2: The non-compensatory change includes interest on the accrued obligation at the start of the year, changes in actuarial assumptions and other experience gains and losses.
3: Mr. Daniel accrued two years of credited service for each year of service between 2001 and 2006. We also granted an additional 13 months of credited service with a company formerly associated with Enbridge, in accordance with the formula in effect before January 1, 2000. In total, Mr. Daniel was credited 7.08 additional years of service.
4: Mr. Monaco participated in the defined benefit pension plan for 1.08 years and in the defined contribution pension plan for 3.00 years prior to January 1, 2000. Mr. Monaco's retirement benefit is calculated using a 2.5% accrual rate for each year of credited service between 2008 and 2013. The higher accrual rate is equivalent to approximately 1.25 years of credited service as of December 31, 2012. Mr. Monaco is not eligible for bonus consideration in the retirement benefit calculation for credited service prior to January 1, 2000. Upon Mr. Monaco's appointment to President & Chief Executive Officer, a cap to the annual pension payable of $1,750,000 was implemented.
5: Mr. Bird's retirement benefit is calculated using a 2% accrual rate from his date of employment until December 31, 1999 and 3.26% for each year of credited service from January 1, 2000 until March 31, 2009. The higher accrual rate is equivalent to approximately 7.1 years of credited service.
6: Mr. Robottom's retirement benefit is calculated using a 4.0% accrual rate for each year of credited service from his date of employment. The higher accrual rate is equivalent to approximately 6.58 years of credited service as of December 31, 2012.
7: Ms. Holder's retirement benefit for each year of service prior to January 1, 2000 was in a contributory pension plan and is calculated with an accrual rate of 2.0% less a CPP offset. Upon retirement this benefit is indexed at 55% of the annual increase in the consumers price index.

Defined Contribution Plan

Mr. Monaco participated in the defined contribution plan from 1997 to 1999 inclusive. None of the named executives are currently participating in the defined contribution pension plan and we have not made contributions to the defined contribution pension plan on behalf of the named executives since 1999.

75 ENBRIDGE INC.

The values shown below reflect the current year end market value of assets for the prior participation in the defined contribution pension plan.


	Accumulated value at the start of the year ($)	Compensatory change1 ($)	Accumulated value at the end of the year ($)

Al Monaco	38,050	–	41,357

1: The compensatory change is equal to contributions made by the company during 2012.

You can find more information about the pension plans starting on page 54.

Termination of employment and change of control arrangements

We have an employment agreement in place for each named executive. The terms in the agreements are competitive and part of a comprehensive compensation package that helps us attract and retain top executive talent.

The agreements generally provide benefits for the executives in three situations:

•: involuntary termination for any reason (other than for cause);
•: voluntary termination within 60 days (150 days in the case of Messrs. Monaco and Robottom and Ms. Holder) after constructive dismissal, as defined in each agreement; and
•: voluntary termination within 60 days of the first anniversary of a change of control, as defined in the agreements.

Messrs. Monaco, Robottom's and Ms. Holder's employment agreements do not include a single trigger voluntary termination right following a change of control because in 2007 we made it a policy not to include single trigger voluntary termination rights in favour of an executive. The agreements with the other named executives were signed before we introduced this policy.

The employment agreements with the named executives contain a confidentiality provision applicable during employment and for two years thereafter and a non-competition provision applicable during employment. Mr. Monaco's new employment agreement signed on February 12, 2013 and effective October 1, 2012 also contains a non-competition provision applicable for 12 months from the termination of employment and a non-solicitation provision applicable for 24 months from the date of termination of employment.

The table below lists the additional compensation that would be paid to the named executives if any of them were terminated.

Type of
termination

Base salary

Short-term incentive

Longer-term incentives

Benefits

Pension

Resignation

None

Payable in full if executive has worked the entire calendar year. Otherwise none.

•   Performance stock options are prorated to resignation date.
•   Vested stock options must be exercised within 30 days of resignation or by the end of the original term (whichever is sooner).
•   Unvested stock options are cancelled.
•   Performance stock units are forfeited.

None

No longer earns credited service.

2013 Management information circular 76

Retirement

None

Current year's incentive is prorated based on retirement date.

•   For the period of active employment in the 5 year period starting January 1 of the year of grant and ending the later of three years after retirement or 30 days after the date by which the share price targets must be met (or up to the date the option expires, whichever is earlier), as long as the share price targets are met.
•   Stock options continue to vest and can be exercised for three years after the retirement date or until the end of the original term (whichever is sooner).
•   Performance stock units are prorated to retirement date.

Post-retirement benefits begin.

No longer earns credited service.

Termination (involuntary, not for cause)

Termination
(constructive dismissal)

Termination
(change of control)

Base salary is paid out in a lump sum:
• three years for Chief Executive Officer; and
• two years for other executives;

Two times (three times for the Chief Executive Officer) the average of short-term incentive awards received in the past two years.

plus

The current year's short-term incentive, prorated based on service before employment was terminated.

•   Vested stock options can be exercised according to stock option terms.1
•   Unvested stock options are paid in cash.
•   Performance stock units are prorated to date of termination and the value is assessed and paid at the end of the term.
-----------------------------------
•   All stock options vest.
•   All performance stock units mature and value is assessed and paid based on performance measures achieved to that time.

The value is paid out in a lump sum:
• three years for chief executive officer; and
• two years for other executives.

Additional years of pension accrual are added to the final pension calculation:
• three years for Chief Executive Officer; and
• two years for other executives.

1: Valued assuming all performance measures have been met.

The table below shows the additional amounts that would have been paid if the named executive had been terminated on December 31, 2012, whether the termination was involuntary (without cause), constructive dismissal or termination following a change of control.


	Base salary1 ($)	Short-term incentive ($)	Longer-term incentive2 ($)	Benefits ($)	Pension3 ($)	Total payout ($)

Patrick D. Daniel	–	–	–	–	–	–

Al Monaco	3,000,000	1,277,235	11,671,584	307,066	3,077,000	$19,332,885

J. Richard Bird	1,450,000	954,620	7,484,623	161,077	2,039,000	$12,089,320

Stephen J. Wuori	1,400,000	968,240	7,449,554	159,330	3,118,000	$13,095,124

David T. Robottom	921,660	726,380	4,550,099	124,540	1,287,000	$7,609,679

Janet Holder	898,800	593,580	5,304,500	142,979	1,020,000	$7,959,859

1: Total for the severance period (three years for the Chief Executive Officer, two years for the other executives).
2: In-the-money value of unvested incentive stock options and performance stock options as of December 31, 2012. Includes the value of outstanding performance stock units as of December 31, 2012 as though the grants had vested, EPS targets are met and P/E performance is top quartile relative to peers with a performance multiplier of 1.5.
3: Value of additional service under Enbridge's defined benefit and supplemental benefit pension plans over the severance period.

77 ENBRIDGE INC.

4. Loans to directors and senior officers

No current or former directors or officers of Enbridge or any of our subsidiaries, or their associates, had any loans with Enbridge or any of our subsidiaries at any time in 2012, other than routine indebtedness previously outstanding as defined under Canadian securities laws.

This routine indebtedness consists solely of loans for relocating to another business location or incentive loans offered to new hires. We offered these types of loans to some officers in the past.

We have not granted, renewed or extended any loans to our directors and officers since Sarbanes-Oxley was enacted on July 29, 2002.

5. Directors' and officers' liability insurance

We have liability insurance for our directors and officers and those of our subsidiaries, to protect them against liabilities they may incur in their capacity as directors and officers. We maintain a coverage limit of US$225 million, which is subject to a deductible of US$1 million for each claim that we grant indemnification for. The insurance program renews annually on October 30 and the premium we paid for the current coverage year is US$1,718,825 net of applicable premium taxes.

We review our coverage program on an annual basis, including benchmarking the level of directors' and officers' liability coverage at other energy and peer sized companies. The Canada Business Corporations Act also contains provisions regarding directors' and officers' liability coverage.

2013 Management information circular 78

		Proxy form
		Registered holders of common shares Your common shares give you the right to vote at our 2013 annual meeting of shareholders. You can vote in person at the meeting, or vote by proxy using this form.

This proxy is solicited by management
and our Board of Directors.
Throughout this document, we, us, our and Enbridge mean Enbridge Inc. You and your mean the securityholder completing this form.

When
Wednesday, May 8, 2013
1:30 p.m. mountain daylight time (MDT)
Where
Metropolitan Conference Centre,
Ballroom
333 - 4^th Avenue S.W.
Calgary, Alberta (Canada)

Two ways to vote — in person or by proxy
You can vote on several items of Enbridge business at our upcoming annual meeting of shareholders. If you are voting by phone or on the internet, you will need your 12-digit control number, which appears in the lower left corner of this form.

A	Vote in person
	If you plan to come to the meeting and vote in person, do not complete or return this form. Simply attend the meeting and register with a representative from CIBC Mellon Trust Company (CIBC Mellon), our transfer agent and registrar for our shares. Canadian Stock Transfer Company acts as administrative agent for CIBC Mellon.
B	Vote by proxy
	Voting by proxy means giving someone else the authority to attend the meeting and vote for you (called your proxyholder).
	You can vote by proxy in one of four ways:
	• By phone — Call 1.866.243.5062 toll-free and follow the instructions • By fax — Complete, date and sign this form and fax to CIBC Mellon at 1.866.781.3111 (in North America) or 1.416.368.2502 (outside North America) • Online — Go to www.proxypush.ca/enb and follow the instructions on screen	• By mail — Complete, date and sign this form and mail it to Canadian Stock Transfer Company acting as administrative agent for CIBC Mellon: Canadian Stock Transfer Company Attn: Proxy department P.O. Box 721 Agincourt, Ontario Canada M1S 0A1
	If you are voting by proxy, please complete all three sections of this form, date and sign it, and return it right away. CIBC Mellon must receive your voting instructions by 6 p.m. MDT on Monday, May 6, 2013.

Appoint a proxyholder
You can appoint an Enbridge officer to be your proxyholder, or choose someone else to attend and vote on your behalf.

o: You appoint Al Monaco, or failing him, David A. Arledge
o: You appoint the following person to attend the meeting and act and vote for you and on your behalf with full power of substitution, according to your instructions (this person does not need to be a shareholder):

(please print name)

You can also appoint a proxyholder on the internet. Follow the instructions on screen.

Give us your voting instructions
Our board of directors recommends that shareholders vote for all of the resolutions below.

The common shares represented by this proxy form will be voted for or against, withheld from voting or abstained from voting according to your instructions, including on any ballot that may be called. If you do not specify how you want to vote your common shares:

•: the Enbridge officer you appointed as your proxyholder in section 1 will vote for each of the items below; or
•: the other proxyholder you appointed in section 1 can vote as he or she sees fit.

If there are amendments or other items of business that properly come before the meeting, your proxyholder has the authority to vote at his or her discretion. If the meeting is adjourned, your proxyholder has the discretion to vote on any amendments or other items of business according to his or her best judgment.

Elect the directors

For

Withhold

For

Withhold

David A. Arledge

David A. Leslie

James J. Blanchard

Al Monaco

J. Lorne Braithwaite

George K. Petty

J. Herb England

10.

Charles E. Shultz

Charles W. Fischer

11.

Dan C. Tutcher

V. Maureen Kempston Darkes

12.

Catherine L. Williams

Appoint the auditors
Appoint PricewaterhouseCoopers LLP as auditors.	For	Withhold
	o	o

Sign and date
If you are sending us your vote by fax or mail, you must sign here for your vote to be counted.

When you sign here, you are:

•: authorizing your proxy-holder to vote according to your voting instructions at Enbridge's 2013 annual meeting of shareholders, or any adjournment; and
•: revoking any proxy that you previously gave for this meeting.

If you have an authorized power of attorney, he or she can sign for you. If your common shares are held in more than one name, either person can complete and sign this form.

For common shares registered in the name of a corporation, estate or trust, an authorized officer or attorney must sign this form and state his or her position and attach proof that he or she is authorized to sign.

Your name
(please print exactly as it appears on the front of this form)

Your signature
(you must sign here)

Date
(if you leave this blank, we will consider the date to be the day this
form was mailed to you)

Position and signature
(complete this if you are signing by power of attorney on behalf of
a corporation, estate or trust)

Send us your voting instructions right away
CIBC Mellon must receive your completed form by 6 p.m. MDT on Monday, May 6, 2013.

If the meeting is postponed or adjourned, we must receive it at least two business days before the start of that meeting.

By fax
Toll free from anywhere in North America:
1.866.781.3111
From outside North America:
1.416.368.2502
Remember to fax both pages of this form.

By mail
Use the envelope provided or mail to:
Canadian Stock Transfer Company
Attn: Proxy department
P.O. Box 721
Agincourt, Ontario M1S 0A1

If you are voting on the internet, you need to complete your voting instructions by 6 p.m. MDT on Monday, May 6, 2013. Go to www.proxypush.ca/enb and follow the instructions on screen.

Nothing is more important to us than the safe delivery of energy that millions of people rely on. ENBRIDGE INC. ANNUAL REVIEW 2012 B D R C E . N E G N I I

DELIVERING ENERGY RESPONSIBLY 2 GROWTH AND EXECUTION 6 BUILDING THE FUTURE ENERGY ECONOMY 14 SOLID INVESTMENT 18 LETTER TO SHAREHOLDERS 22 CORPORATE GOVERNANCE 27 FORWARD-LOOKING INFORMATION 28 2012 AWARDS AND RECOGNITION 29 INVESTOR INFORMATION 30 Forward-Looking Information: This Annual Review includes references to forward-looking information. By its nature this information applies certain assumptions and expectations about future outcomes, so we remind you it is subject to risks and uncertainties that affect every business, including ours. The more significant factors and risks that might affect future outcomes for Enbridge are listed and discussed in the “Forward-Looking Information” section on page 28 of this Annual Review and also in the risk sections of our public disclosure filings, including Management’s Discussion and Analysis, available on both the SEDAR and EDGAR systems at www.sedar.com and www.sec.gov/edgar.shtml, respectively. Millions of people across North America rely on Enbridge every day because we transport, generate and distribute the energy they need for their daily lives. At the same time, there’s a huge transformation underway in North America in terms of where and how energy is being produced and the markets it needs to reach. As a leading energy infrastructure developer and operator, Enbridge is responding decisively to this changing energy landscape so that we can continue to provide the energy North America—and the rest of the world—wants and needs. We’re expanding our pipeline networks and our renewable energy generation capacity, and at the same time we’re developing new business platforms. As we grow, nothing is more important to us than the safety and operational reliability of our assets. You place your trust in companies like Enbridge to deliver your energy safely, reliably and responsibly, and that will always be our number one priority in everything we do.

Our customers and the public trust us to deliver energy safely, and we’re doing everything we can to keep their trust. AL MONACO President & CEO Visit our annual report online and watch a conversation with Al Monaco: enbridge.com/ar2012 > 1 A M NA L C O

We’re building on a strong foundation for the future of Enbridge and the global economy. DELIVERING ENERGY RESPONSIBLY 2 < ENBRIDGE INC. 2012 ANNUAL REVIEW IV IN N N I L LY Y E E E E E D R R R P B

WHAT WE DO The global energy landscape is changing. Rapid growth in North American energy production has put the continent on the road to energy self-sufficiency; and globally, demand for energy is growing, led by emerging markets, particularly in Asia. Enbridge is uniquely positioned to deliver the energy North Americans need today and benefit from new and emerging opportunities tomorrow. We safely and responsibly deliver energy through our North American-wide energy infrastructure. We’re also aggressively expanding our infrastructure, investing in innovative renewable power generation and investigating new opportunities to help the world meet its future energy needs. LIQUIDS PIPELINES Our mainline system is one of the largest, most complex crude oil systems in the world. It’s also the largest conduit of oil into the United States. We transport 53% of U.S.-bound Canadian production, which accounts for 15% of total U.S. imports. Our existing systems are strategically located to attract growing North American energy supply and serve premium markets. For example, we’re the largest crude oil pipeline operator in Alberta’s oil sands region—which is one of the largest proven oil resources in the world—and we own and operate the largest pipeline infrastructure in the Bakken region of southeastern Saskatchewan and North Dakota, which has quickly grown to become one of the leading oil producing regions in North America. GAS PIPELINES & PROCESSING We have significant investments in natural gas pipelines and processing infrastructure. Our natural gas systems extend from northern British Columbia to the Gulf of Mexico. Our offshore pipelines transport approximately 50% of the natural gas produced in the deepwater Gulf of Mexico. As a new platform for growth, we recently entered the Canadian Midstream natural gas processing business focused on growing unconventional gas production in British Columbia and Alberta and complementing our existing joint-venture interests in the Alliance Pipeline and the Aux Sable fractionation plant near Chicago. GAS DISTRIBUTION We’re the largest natural gas distributor in Canada; and today, our Ontario-based Enbridge Gas Distribution is delivering affordable clean-burning natural gas to over 2 million residential, commercial and industrial customers. RENEWABLE AND ALTERNATIVE ENERGY Our renewable power generation assets in Canada and the United States— including 10 wind farms, four solar projects, a geothermal installation, and four waste heat recovery facilities—have the capacity to generate more than 1,300 megawatts (MW) of emissionsfree energy—enough to power almost 410,000 homes. In Canada, we’re the largest generator of solar energy and the second largest wind energy generator. POWER TRANSMISSION We recently entered the power transmission business in North America and are currently considering opportunities for additional investment. INTERNATIONAL We’re looking to establish asset positions in countries with strong energy export fundamentals, favorable investment climates, and significant infrastructure development needs. For example, we’re currently sponsoring the development of the Oleoducto al Pacifico pipeline, a proposed heavy oil pipeline to the Pacific coast of Colombia with significant support from potential shippers. THE ENERGY WE DELIVER Delivering Energy Responsibly > 3 D R R Y G E E E V I L E W E N E H T

HOW WE OPERATE Because millions of North Americans count on the energy we deliver daily, we know we cannot compromise on the steps we take to ensure maximum safety and reliability, year after year. People want to know what we’re doing to continually improve—to prevent incidents, improve safety and reduce our industry’s environmental impact. The safety and integrity of our operations is our highest priority. Over the past decade, we’ve transported almost 12 billion barrels of crude oil with a safe delivery record better than 99.999%. However, we know that’s not enough, because anything less than 100% isn’t acceptable to the public, nor to Enbridge. We’re focused on establishing Enbridge as the industry leader in safety, operational reliability and environmental performance through a variety of company-wide initiatives. FOCUS We’ve re-organized Enbridge (the Company) to ensure we’re constantly focused on operations safety and system integrity. Our Operations and Integrity Committee chaired by the CEO is the most important executive committee in the Company. Our Operational Risk Management Plan, which is a road map of programs that are required to sustain Enbridge’s industry-leading position, is as important to us as our Strategic Plan. INVEST We’re investing heavily in the tools, technologies and strategies that will ensure our energy transportation and distribution systems have the strength to perform safely, reliably and in an environmentally responsible manner. Our goal is—and will always be— to prevent all releases from our systems. In 2012, we invested $800 million in programs and initiatives to improve our pipelines and facilities. We’re committed to constantly reinforcing the safety and integrity of our systems and being best-inclass in the industry in key areas such as pipeline and facility integrity, third-party damage avoidance, leak detection, incident response, occupational and public safety, and environmental protection. Our objective is straightforward: to achieve best-in-class performance across all critical safety and integrity dimensions. STABILIZE We’ve formally committed to stabilizing Enbridge’s environmental footprint through our Neutral Footprint program. Since 2009, we’ve been neutralizing the environmental impacts of our growth projects—planting a tree for every tree we remove; conserving an acre of natural habitat for every acre we permanently impact; and generating a kilowatt hour of renewable energy for every kilowatt hour of additional power our operations consume. To learn more about the Neutral Footprint program or for quarterly updates on our progress, please visit our online dashboard at enbridge.com/neutralfootprint HOW WE SUPPORT SOCIETY Enbridge plays an important role in society and we take that responsibility very seriously. Our primary responsibility is to deliver the energy North Americans need in the safest, most reliable and most efficient way possible. People throughout North America rely on the energy we deliver. Energy enables commerce and economic growth. It powers homes, offices and factories, schools and hospitals. It moves people, goods and information. In fulfilling that responsibility, we create jobs in Canada and the United States and we provide significant and quantifiable direct economic benefit to a broad group of stakeholders in the form of shareholder returns, employee compensation, community investments and government tax payments. CORPORATE SOCIAL RESPONSIBILITY Enbridge employees believe in transparency in all aspects of our business, including transparent, proactive and frequent communication with our stakeholders. One way we demonstrate that commitment is our annual Corporate Social Responsibility ( CSR) Report, which provides detailed information on Enbridge’s economic, environmental and social performance. To read Enbridge’s CSR Report, please visit csr.enbridge.com csr.enbridge.com/summary 4 < ENBRIDGE INC. 2012 ANNUAL REVIEW O S I P R R AT A C O O C E L S P B R O Y S E T I L I I N i l i i b m o e n v n e e e g d e e e r b p s l E y l i r s n e o o n n s a e tr r c a p p c a a s u t f l y i i i s d n n n n n s g p b e e r r c a a s s t u t l u , , i i f i r n e o o o c r n n e n mm p d q e t c a c a a u t t u v O i r o o e h n e d h e e r k s a a s. w t t w l u w y i t i mm o o o e m m s e d n h n e t r r c a a s u t t t t C i l i R i i r a sp e p o o o o n n n e r a b S c a a s t t l l u y ) i i h C R i rt r s o o e v h p d e e e R c p d d S a w t l , i i i i ’ m n e e o o o o o c n f m n s g n n r r b d c at E , i i rf a m c n o o o r p n n n r c m d n e e e e t a a a s . l l v i R R C ’ a p o o n a g d e e e e e re r p b d S s s rt l E , b i i i r m o r n g d e e c c s s . r. t v

JOBS In 2012 alone we added 1,476 people to our team in Canada and the United States to support Enbridge’s unprecedented growth and help us deliver our growth projects. In addition, our projects create thousands of skilled construction jobs in communities across North America, generate hundreds of millions of dollars in labour-related income, and create additional permanent jobs when the projects become operational. Communities along the routes benefit because Enbridge engages local workers and local businesses during the planning, building and operation of the facilities. Our projects also stimulate the purchase of goods and services in and around those communities. We also work with Aboriginal communities to ensure they achieve sustainable benefits from our projects and operations, including opportunities for equity partnership, training and education, employment, procurement, business development and community investment. DIVIDENDS In 2012, Enbridge declared dividends of $1.13 per common share, equating to a total value of $895 million to Enbridge Inc. common shareholders. COMMUNITY INVESTMENT We believe investing in our communities is an essential part of being a good neighbour. For example, in 2012, our enterprise-wide community investment expenditure totaled $13 million, which we invested in more than 550 charitable, non-profit, and community organizations. In addition to investing with our dollars, we also invest through partnerships and by supporting the volunteer efforts of our employees. We focus on supporting organizations that contribute to the economic and social development of the communities where we live and work. SAFE COMMUNITY enbridge.com/safecommunity Through our Safe Community program, we provide grants to local first responders in areas we operate to help with equipment, training, public awareness and volunteer recognition. Since we launched the program in 2002, we’ve contributed over $ 5.7 million in grants to first-response organizations across North America. The inline inspection devices we use to inspect our pipelines are so sophisticated, they can sense and measure the size, frequency and location of even minute changes on both the inside and the outside of pipe walls, providing a level of detail similar to that provided by MRI, ultrasound, and x-ray in the medical industry. Walter Kresic, Vice President, Pipeline Integrity, Enbridge Inc. Delivering Energy Responsibly > 5 O C AF Y S U E T I N M M i i m m s o c t e e e o n m b g n r d c a y u f . / h i m o o o n h m g e r r C Sa t u u u f T y l i r o o o o p r r m n g g e e r a p d c a a s t t l v w , i f i r r r r n o o n s s a e p d e e e e e r p a a s st t w i i i i t h o e e n n u t n m p g he t ra p q w t l , , i r a c o n n n d e e e e r b p a s a s t u l v w l u i i i h n n n o o h t c c g n e e e e e r c d S a . w t u l 0 0 t 2 i i ’ n e o o n m r g e b p d e r r c u a w v t 2 , i l l t i i 7 n n m o o o r n g e r 5 a s t . v t i i i o o or r s n n e p g n e r - a s a s s ti z f i r o o h m c a e r A a c s s . rt N

We’re executing the largest capital program in Enbridge’s history– safely and responsibly. GROWTH AND EXECUTION 6 < ENBRIDGE INC. 2012 ANNUAL REVIEW H AN I N U EX WT E T R D

CHANGING MARKETS There’s an urgent need for more energy infrastructure in North America, and Enbridge is playing a critical role in providing it. We’re building new liquids and gas pipelines to help our customers access new markets, expanding our gas distribution network to meet growing demand from consumers and expanding into new business areas, such as Canadian midstream gas processing and power transmission—all in response to the changing North American energy landscape. What’s happening in the global energy marketplace that is driving Enbridge’s growth? SUPPLY GROWTH Rapid technological advancements have revolutionized the North American energy industry. Horizontal drilling, new reservoir stimulation methods and economies of scale have unlocked massive unconventional crude oil and natural gas reserves, leading to a surge in oil and gas production. As a result, we’re seeing substantial growth in energy production across the continent—in Alberta’s oil sands, in the Bakken region of Saskatchewan and North Dakota, in Texas, and in several large, unconventional natural gas resource plays. This means that North America is now within reach of energy self-sufficiency, and the United States has the potential to become the world’s largest oil producer. U.S. production is forecast to double to 12 million barrels per day (bpd) over the next two decades, and Canadian oil production is expected to double to 6 million bpd over that same time frame—putting Canada in the top four oil producing nations. BOTTLENECKS & PRICE DISCOUNTING This supply growth has resulted in significant transportation bottlenecks between growing oil and gas supply regions and both continental and global markets. Although North America has well-developed pipeline infrastructure, currently there’s not enough infrastructure in place to meet shipping requirements and, given the location of unconventional reserves, the infrastructure is not always in the right places. This has resulted in price dislocations, with North American energy resources being heavily discounted relative to world prices. The situation is particularly acute for Canada, where the bulk of energy resources are land-locked and have access only to the United States market, which has access to multiple sources of global supply. This means lost value for Canada of about $75 million per day and billions of dollars a year for crude oil exports alone. ENERGY 101 VIDEO The world consumes approximately 90 million barrels of oil every single day for heating our homes, growing our food, transportation, power generation, manufacturing and countless other essentials in our lives. Through our complex network of pipelines, Enbridge plays a key role in moving energy from where it’s found to where it’s needed. enbridge.com/energy101 COMMERCIALLY SECURED GROWTH CAPITAL (billions of dollars) By January 2013, Enbridge had an enterprise-wide total of 27 billion of commercially secured growth investments across all our business segments, all of which are expected to come into service by 2016—the largest capital program in the Company’s history. 10 13 14 17 18 27 Q4 12 Q3 12 Q2 12 Q1 12 Q4 11 Q3 11 Growth and Execution > 7 O D 1 R Y 0 G E I V 1 E N E T i r m o o o c n h m u w p e p d e e r x a a s s t l l y l l i 0 f 9 i i i r m n e e o o o b g n e e r a s s v l l l ry i d f i r s m h o o o o o e t h n ng g g e r r r u a a u w , y i i r r p n o o o o o o n n n g p e e e t rt tr a a d a s w ti f , , , l t i s m n o o n n n s d g he e t r r a a u c c a u u t f li i i s g o o o t h h n n e e e ro r r a u u s s . s v u T i l i E i i m n n o o o e n r x c b g p p e e e e r p d s t l f k w l , i i l f a m o o o r r n e e m g e p g ne r s v l k y y y d i i ’ ’ d d h n e o o r h s n e e e e e e r . s w t t t w u f B 0 i a e n g b h n r 3 E J d d a a 1 2 u , ry y i i d o o e n n e e e r r - p a a s t t t f l w d i f i i 7 s m m e e re o o o $ b n e r r c a c c u l l l l 2 y l l i t s o o o r en v n w s m g h e t t r r a a s c s u i f i m g o h n s n a e e e b h t c s s s s w l l u , i i r m o o o e c t x c n e e e e e re e t p d c a s t rv l i h 0 2 6 1 a p b rg e e t t — c a s a t l y i ’ h i s a s p p o o o r m n am g h n e r C t t y. ry. y

DEMAND SHIFT Additionally, the global demand picture is changing. In coming years, energy demand will not, as in the past, be driven by North America or Europe, but by emerging markets, primarily Asia and India. We expect demand for electric power and green energy will continue to grow in North America, presenting opportunities in both power generation and transmission. ENBRIDGE’S RESPONSE Enbridge is responding aggressively to these profound market changes and challenges by investing tens of billions of dollars to expand our pipeline network to connect supply with demand, while also developing new business platforms to extend the Company’s sustained record of exceptional growth beyond the middle of this decade. ENBRIDGE’S MARKET ACCESS INITIATIVES Our commercially secured Light Oil, Western Gulf Coast, and Eastern market access programs respond to fundamental shifts in the crude oil supply and demand patterns in North America. Our shippers have asked us to provide increased transportation of crude oil—and in particular, rapidly growing supplies of light crude oil—between growing producing regions and major refinery hubs, and we’re delivering. LIGHT OIL MARKET ACCESS This $6.2 billion initiative is a suite of projects in Canada and the United States to expand access to markets for growing volumes of North Dakota and western Canada light oil production to premium refinery markets in Ontario, Quebec and the U.S. Midwest. The individual projects within the initiative are targeted to be available for service at varying dates from 2014 to early 2016 and will provide new market access for approximately 400,000 bpd of additional light oil. EASTERN ACCESS This $2.7 billion suite of projects establishes a path for western Canadian and Bakken crude oil to access refineries in eastern Canada and the midwest and eastern United States. For example, by reversing the flow of our existing Line 9, Ontario and Quebec refineries will have access to lower-cost western Canadian feedstock—Ontario and Quebec currently derive 18% and 90% of their crude from higher priced offshore sources, respectively. WESTERN GULF COAST ACCESS This $6.4 billion initiative, whose major components are the Seaway Pipeline reversal and expansion and the Flanagan South Pipeline, connects Canadian heavy oil supply to the vast refinery AT A GLANCE—COMMERCIALLY SECURED CRUDE OIL MARKET ACCESS PROJECTS PROJECTS IN-SERVICE DATES TOTAL SECURED CAPITAL 1 Light Oil Market Access 2014 – 2016 $6.2 billion Eastern Access 2013 – 2014 $2.7 billion Western Gulf Coast Access 2012 – 2014 $6.4 billion 2 1 As of January 2013 corporate-wide 2 Inclusive of a number of related mainline expansion projects NEW REALITIES “ Canada today lacks sufficient energy infrastructure to access the best U.S. markets and we have virtually no export capability beyond the U.S. market— forcing Canada to sell its most valuable export at a massive discount. In my view, there is no more critical issue facing Canada today. The solution is clear: we must build the infrastructure to connect our production with the best North American refining centres and the growing economies of Asia and do so in an environmentally sustainable way.” Al Monaco, President & CEO, Enbridge Inc. January 30, 2013, Alberta Enterprise Group, Edmonton, AB enbridge.com/marketaccess 8 < ENBRIDGE INC. 2012 ANNUAL REVIEW C d i i a d n o e n g n e e t r a a s c c a a s u t ff k l y y S i r s s c o h n e e c e b e t t r r U c s a a s t t t . . u u f l k i r m e o o h v v n e e e n rt p d u a a a a s rt t x l w y i i a o r n t p h m e d e e — k U b b S a a c t t . . l y y l l i C i s m e b o o o c a s a d g n n e r a u a a s t t t v l l f i i s m o o e e n p s a m d n c s a . t rt v t I u x y i l i i i i r a m e e o o n s e h e e t r r w c s c s t u v , i f i i a n o o o n s s g h n e C a a d da ac t ut l T y. d i f t i r s a e h w n m c e e e t t r r r: bu c a s u u t l u : l h i i s co o o o o r e n t n t w h c c n e e r b p d u t u t t t h f i i i Am o e re n n c e e e re g d n n n h e r c a a s rt t t N i i f i i A ro s s d d n n e o o o o o om a a n g g n e c s w ” b i i s m o ro n n n n n e e e ay u a a a a st t y. w l l l v y ay. M O P A o o i i e e d n r g n n d e n r c c b C a s E I E l . , , t Ed i 0, 20 A 3, on on an dmo lbe rp se ary Gro te up rta Ent Edm be pri erp ert Ja A to o ro 3 ise ta ua Gr oup En ris Alb 1 n, p, ry

complex along the western Gulf Coast near Houston. The Flanagan South Project will add 585,000 bpd of capacity between Enbridge’s Flanagan, Illinois terminal and Cushing by mid-2014. EASTERN GULF COAST ACCESS In response to significant interest from both producers and refineries, Enbridge and Energy Transfer Partners, L.P. announced plans in February 2013, for the joint development of a project to provide crude oil pipeline access to the eastern Gulf Coast refinery market from the Patoka, Illinois hub. Targeted to be in service by 2015, the pipeline will have capacity of up to 420,000 to 660,000 bpd, depending on crude oil slate. This initiative would create the first pipeline transportation option for crude oil to the Gulf Coast from the U.S. Midwest and is an important component of our broader plans to open up access to the Gulf Coast crude oil market. Crude oil can reach the Patoka hub from both western Canada and the Bakken play in North Dakota through a variety of existing pipelines, as well as through Enbridge’s Southern Access Extension Project, which is already under development. WESTERN ACCESS Our proposed Northern Gateway Project would transport 525,000 bpd of oil from Alberta for export to refineries in the Asia-Pacific region and U.S. west coast. The project involves a crude oil export pipeline and condensate import pipeline between Edmonton, Alberta and a proposed new marine terminal in Kitimat, British Columbia. Public hearings on Northern Gateway began in January 2012. Designed to be world-class in every respect, the project would be of POSITIONED FOR GROWTH “ Enbridge’s network is advantageously positioned geographically to connect North America’s growing supply regions with the best refinery and consumer markets across the continent. The strength and scale of our network is also allowing us to extend into new markets and is leading to more opportunity for the Company.” Steve Wuori, President, Liquids Pipelines & Major Projects, Enbridge Inc. RAIL SOLUTION enbridge.com/rail Enbridge is investing in loading and unloading rail facilities as a near-term solution to increasing export capacity and clearing transportation bottlenecks out of the fast-growing Bakken region. Our Berthold Station Expansion Project is expected to add an additional 80,000 bpd of takeaway capacity to market hubs and refineries across the North American rail network by early 2013. Also, Enbridge and Canopy Prospecting Inc. have created the Eddystone Rail Project to develop a unit-train facility and related local pipeline infrastructure near Philadelphia, Pennsylvania to deliver Bakken and other light sweet crude oil to Philadelphia-area refineries by the end of 2013. Eddystone Rail is expected to handle 80,000 bpd initially and can ultimately be expanded to receive up to 160,000 bpd. enbridge.com/lightoil Growth and Execution > 9 The Seaway Pipeline is our 50-50 joint venture with Enterprise Products Partners L.P. (Enterprise). In May 2012, the flow direction of the pipeline was reversed, allowing it to transport crude oil from the bottlenecked Cushing, Oklahoma hub to the Gulf Coast. Capacity available to shippers was then expanded in January 2013 from 150,000 to 400,000 bpd, depending on crude oil slate, although actual throughput has been curtailed due to constraints on third-party takeaway facilities. Enbridge and Enterprise are also planning to twin the pipeline by early 2014, which will more than double Seaway’s capacity to 850,000 bpd by mid-2014. O D N P R R O F G S O E I T I i i ’ a n o o r n s n b g g d e e e t rk a d a s s E t l u v w y i i i c c n p o o o o o c n r a h d g g n e e e t p a s t t l l y i i i ’ ro m g n o o o re r h p ns s s g g e e w A p ca rt u l N y i i s ne e e e on h m n h e r r b d c a s t t t u f w ry i h r m n o o e n h n e e e r c ac k a s s . s t t t t T i r s n c o o o n n h d g e e e r r a k a s s w t t t u f l i i n o o o o n n nd g e e e a a s s w t t t x u w l l l i i s m n o o n e m g e e r rk d d a a a s t t l ” C i p m e o o o op n n h r rt pa u t t y. f y S i i i P P r e o t i i i s n n d e p d e re e e s q s t u L l u W v , , E j P j i e o o ri n t g b n e r r a c d c s, I M . O I R O A S U N I T L L l i i r e e m o g n r b d c a . / i l d l i i i i i t t f i i i i i i r d m n n n o o o o e e n r n n n n n s g g g g b n e e e r r- E a a d d a c a a a a s s s s t u t l l l u v l i i i i f t i s a a s g c n e re o o o o o o o n n n p n c g p h n n e e e e e t tr r rt c c k b p d c a a a at a s t t t t t rt u l x y O i E i h B B P S f i j i i r s a d n o o o o o ro oje p n n n d g g g n n e e e e re e e rt t ro c a p - k s c at a . s w t t t t x x l u k k d i 0 0 0 0 8 t f i i r a d m o o o o e n n c c ay h b d d e p d d n t a a a p b a a a a a a s t t t t u w k l , y y i E i N i 0 i i r r r re r s s n m e o o o o ro n n t r n c s h h e e dge e e e e r A A a b b 3 c k a a a . s 2 t rt l 1 l w l f , y y C d j l h P P R i i re a a s p o o o ro o o o roj n e e e h c n n e e e g d d d d n n e e e t t ro c c a a p p c a . s v E t t t t l v I y y i i P f i i i i i i i r r s p h h c n n n n e o n n e re e e e e re e t r r - a a p p d d d u c a a a c a a a a t u u t t t t l l f l l l l l , y i h B i l P P t i i i i r a d h o o o o re r r h h e e n n t n v n s s p d g n e e e e e e e e k d d -a a a a c a a a w v t u t t l l l l k l y b l i l R h i f 8 0 0 0 0 0 t 3 i i d d h c e e re o o n n r n n e e o d e e e e e e p p b d d d a s s a , s t t t x E . 1 2 f y y d i l d l i 0 0 0 0 1 t i i i a a a c b m n n o o e e e e e re p n 6 t t p u v n p x y t u b e e t d d a a c . l l , y

significant value for Canada, achieving the goal of diversifying Canadian energy markets and maximizing the value of Canada’s resources. MAINLINE & REGIONAL EXPANSIONS We’re expanding our mainline and regional systems, which are strategically located to attract growing crude oil supply and deliver it to premium markets across North America. Enbridge is the largest infrastructure operator in both Alberta’s oil sands and the Bakken play in North Dakota and Saskatchewan—two of North America’s largest domestic energy supply growth regions. Our infrastructure in both regions is connected directly to our mainline system, the largest crude oil system in the world with 25,000 kilometres of pipeline across the continent. As a result of our scale, existing rightsof- way, construction expertise, and strong stakeholder relationships in these regions, we’re currently expanding our network through numerous commercially secured projects and we have many more opportunities under development. MAINLINE EXPANSION In order to ensure adequate capacity on our mainline system to supply our new market access projects, we’re planning to expand our Alberta Clipper and Southern Access pipelines to their maximum capacities through the addition of new pumps and pump stations. We’re also planning to add capacity to the upstream end of the system to accommodate the volume growth we’re seeing at the Edmonton hub. We’ll achieve this by building a new $1.8 billion, 36-inch line between Edmonton and Hardisty, Alberta with initial capacity of 570,000 bpd, expandable to 800,000 bpd, and a target in-service date of 2015. ALBERTA REGIONAL INFRASTRUCTURE We’re investing $3.4 billion to expand our oil sands infrastructure. Enbridge is the leading pipeline operator in the Fort McMurray to Edmonton/Hardisty corridors. Our infrastructure currently connects six producing oil sands projects to our Athabasca and Cheecham terminals, and we plan to add two more projects by 2014. As a result of this regional supply growth, we’re expanding the capacity of our existing Athabasca and Waupisoo pipeline systems; twinning the Athabasca Pipeline; and have gained regulatory approval to construct the Woodland Pipeline Extension, which will effectively twin our Waupisoo Pipeline. BAKKEN REGIONAL INFRASTRUCTURE In 2013, we’ll complete and bring into service $0.8 billion of infrastructure expansion projects in the prolific Bakken region in North Dakota and Saskatchewan to provide the region’s crude oil producers reliable, economical and secure access to a wide variety of refinery markets. AT A GLANCE—COMMERCIALLY SECURED REGIONAL EXPANSION PROJECTS PROJECTS IN-SERVICE DATES TOTAL SECURED CAPITAL 1 Alberta Regional Infrastructure 2012 – 2015 $3.4 billion Bakken Regional Infrastructure 2013 $0.8 billion 1 As of January 2013 EXECUTING MAJOR PROJECTS enbridge.com/expansion “ It’s fundamental that we execute projects safely, on time and on budget. We have an experienced Major Projects management team and 1,300 professionals along with thousands more contractors in the field to execute our current slate of work. In 2012, we delivered four projects at over $ 1 billion—all on time and below budget—and we’re in excellent shape to deliver another 17 projects into service in 2013.” Byron Neiles, Senior Vice President, Major Projects, Enbridge Inc. 10 < ENBRIDGE INC. 2012 ANNUAL REVIEW / i i r n e e o ns o e n p g m b d c a . x i l j f t t t’ s s p m m n e e o o n n h e e e d e e e r c a a a s c a w t t t t u x l u f I y, P h W j j i M r r a a o o o e e v n n n d g d n e e e e e e r p b d c c aj a s t t x . u i l l 00 f i a a s m m m h n o o o n n w n n e e g g e e t r p 3 d a a a a s s t t 1, l h i i r s a s c n o o o o o o he n t m n s d e e e e e re t t r r x c a d c u u u t t t f 0 f f 2 2 j i r re r e p o o o o k r t t n n d e e e e e e ro re d c a a c s s w w u u t t v l 1 I . l , l l l i i i ’ d d m o o o o r n w n an g d b b n e e e e e er — — b a a w t t u l l v j i l 7 t i i r p o o o o n n e e e v n n h e e e h e e r r c p d c a a s s t t t t 1 l l x ” i 0 2 i c n e e 3 s . 1 rv i B E j M i P V P S ro N i j i i n n n n n d o o o e e r r r g b d c e e e e e e r r c a s s c s t . t I l , , , y

GAS PIPELINES & PROCESSING GROWTH We’re developing and pursuing attractive growth opportunities to add to our already significant investments in natural gas pipelines and processing infrastructure in both Canada and the United States. ONSHORE PIPELINES With its unique ability to transport liquids-rich gas, Alliance Pipeline is poised to benefit from rapidly rising production growth in a number of liquids-rich natural gas shale plays, particularly the Bakken play in Saskatchewan, North Dakota and Wyoming and the Montney and Duvernay plays in British Columbia and Alberta. In the United States, the 280,000 bpd Texas Express Pipeline is scheduled to go into service in the third quarter of 2013. Texas Express will enhance access for mid-continent natural gas liquids to the Gulf Coast market. OFFSHORE PIPELINES In 2012, Enbridge was selected by Anadarko Petroleum Corporation to build, own and operate a crude oil pipeline in the Gulf of Mexico to connect the proposed Heidelberg development, operated by Anadarko, to an existing third-party pipeline system. We expect the Heidelberg lateral pipeline will be operational by 2016. In addition, we’re currently developing the $0.4 billion Walker Ridge Gas Gathering System, $0.2 billion Big Foot Oil Pipeline and $0.2 billion Venice condensate expansion, all of which are scheduled to be in service for our customers by 2014. PROCESSING In 2012, we took another step in the execution of our strategy to establish a strong position in the Canadian Midstream business when we entered into a midstream services relationship with Encana Corporation to develop gas gathering and compression facilities in the Peace River Arch (PRA) region in northwest Alberta. The PRA region is in close proximity to the Alliance Pipeline. REMEMBERING THE PAST, CELEBRATING THE PRESENT The Mohawk Council of Akwesasne ( MCA) and Niagara Gas Transmission Ltd. ( NGTL), a wholly owned subsidiary of Enbridge Inc., have built a trusting relationship that formed the basis for a cooperation and land use agreement that they both signed regarding NGTL’s activities in the Akwesasne community, which is situated in eastern Ontario, near the Canada-U.S. border. The agreement also provides for an ongoing relationship between the MCA and NGTL/Enbridge that will contribute to long-term economic opportunities for the community. ECONOMIC DEVELOPMENT csr.enbridge.com/economic-benefits “ With new construction, there’s going to be an influx of workers into communities along the route, meaning increased business for a wide range of local suppliers.” Denise Hamsher, Director of Planning, Major Project Development, Enbridge Inc. csr.enbridge.com/akwesasne Growth and Execution > 11 P B R E R H AS G E T, E T N I M M E S C B P G R R E AT E T N E E H T N I E L C f i A o o o e n h s n h e e kw as c a l u k w M T CA) i i i Tr r s o n m n n ag A) a a d a a a s s s G N M N L) i i d o o h d b ne a d u s s w L G t w l l T . , y ry h i i i s n n o r f e g g n e t r c E a b b d . av t t u l u I , i l t i i at s o o o n h h m p d b he e e re t r r as a s t t f f l t ti d n o o o n n n us m e e g e e er r a p d a c a a i b i i T ’ h o h h s n n g g g e re e e t t rd G a d d a s t L’ t N y i i i i i m m h o n n n e e v s e e t c A a s s c a t u t t kw y, O i h i i i i r s a e o n h u n n n d e e e t r r a a a c s s t t t w , h m o n r t C n a e d d rd g h e re e e e e -U S b a a a r. t T . . i i i i at re s e o o o o ro o o n n n p h ng g d e r a p a a s s l f v l N i A n e h r n n e g b e e e t C a b d d G L/ t E T M w i i i b n o o o o o c n n e h m m c c g e e t r r - at t t t t l u l l w h i i i m o o o o e p c rt m n n e r p s u u t t t y. f y / i i i r n m o e o c c r m o e e e e n g n f -b b d c c s s t . . W i i ’s h h o o n n t s n e e e t re r c c w t u t , k f i i r n e e b o o o o n t ng g r a u s w f x l i i i r m o o o o e n n n m g h e e t c a s t u u t t l , i f i i s m n n n o r e e b g d n e e r u s c a a s si l l l i i ” ra s p e e o o ng e r ca p d s . u f w i D P i D r, m e in o c o n e e h r g nn e r a a s s t i l f H , i E j P j

GAS DISTRIBUTION GROWTH We’re expanding our natural gas distribution business in eastern Canada, which includes Canada’s largest local distribution utility and one of the largest and fastest growing natural gas distribution companies in North America. In early 2013, Enbridge Gas Distribution Inc. (EGD) passed the 2-million customer milestone. EGD now delivers safe, clean and affordable natural gas to residents and businesses in more than 100 communities across Ontario. EGD is planning to invest approximately $0.6 billion to expand its natural gas distribution system in the Greater Toronto Area (GTA) to meet the demands of growth. The project represents the most significant upgrade to the distribution system in 20 years. Subject to Ontario Energy Board approval, construction is targeted to start in 2014, with an expected completion date by the end of 2015. Over the last 20 years, EGD has almost doubled its total number of customers. EGD is also focused on safety and helping customers use natural gas wisely. FOCUS ON SAFETY The safety of our employees, customers and the public is EGD’s top priority. In 2012, EGD opened its new state-ofthe- art Technology and Operations Centre, the hallmark of which is an innovative “streetscape”—the most comprehensive and realistic training facility for a natural gas utility in Canada. The 1.5-acre streetscape consists of: infrastructure common in an urban community with a natural gas distribution system; full-sized roads; and scaled-down buildings that represent residential, commercial and small industrial customer premises. Compressed air is used to simulate natural gas and offers a controlled, safe environment for training. Inside, the facility offers practical, hands-on learning, as well as traditional classroom environments. In keeping with EGD’s long-standing commitment to sustainability, the Centre was designed to meet the Leadership in Energy and Environmental Design (LEED) gold level designation. It’s been designed to use 78% less natural gas, 68% less electricity, 50% less water and produce 50% less waste when compared to a facility of similar use built to building code standards. FOCUS ON ENERGY USE EGD has over 30 programs that encourage its customers to adopt energy-saving equipment and reduce their consumption of natural gas. Since 1995, these programs have: Resulted in net energy savings to our customers of approximately $2.1 billion; Helped customers reduce their natural gas cumulative consumption by about 7 billion cubic metres—the equivalent of enough gas to supply approximately 2.3 million homes for one year; and Avoided over 13.3 million tonnes of carbon dioxide emissions. ELECTRIC POWER TRANSMISSION Enbridge’s first power transmission project is targeted to go into operation in the second quarter of 2013. The 300 MW Montana-Alberta Tie-Line (MATL) Project is a 345-kilometre transmission line from Great Falls, Montana to Lethbridge, Alberta, designed to support the electric transmission needs of new wind power facilities in northcentral Montana and buoyant power demand in Alberta. Once MATL is in service, we plan in the near-term to double its capacity to 600 MW. We’re also currently looking at opportunities for additional transmission investment in both Ontario and Alberta. ENERGY USE – SAVING CUSTOMERS $2.1 BILLION enbridgegas.com/manage-energy “ Through Enbridge Gas Distribution’s multiple demand-side management programs, we’re working with our customers to increase the efficient use of valuable energy resources, thereby lowering each household’s energy costs and impacts to the environment. Since 1995, these programs have resulted in net energy savings to our Jennifer Murphy, EHS Specialist, Enbridge Gas Distribution 12 < ENBRIDGE INC. 2012 ANNUAL REVIEW customers of approximately $ 2.1 billion.” i n n m e a e e e c m o en d g g g g r r s - b a a . / y D t i i i i ’ r b o o r h n u n s h e b g g r G d s s a E t u T i i m m e n s n m m e g d d n e e e t a a p d - a t u l l i i ’ m o o o r r r r r h g e g n e k a p s w w t u w , i i i r s m n h o o t n e e e e e e e t r cu c a c s s s u t t ff h r n o o e e e s g e e e e f r r r b b s rc a a v t u l u l , y y d h i l ’ s h n e o o o n g r h g e e e e r c a s l u w y i i s m o o o e c n m h p n s n n e e t t r d c s a a . v t t t i 9 t 9 m h o n h s e e p g e e r r 5 S a a c s v 1 , i i o o r r e n n n d g g n e e e e t r a s s s t u u t v l y 2 i i i ” s m p p o ro o o o r m n e e t c b u a at rs . . l l 1 l x f y M f i r h e e n n rp J u y, i H D t i i i i i n p e o r g b e n r c G S d b S u a a s s s E l E t t ,

Toledo Superior Patoka Wood River Chicago Hardisty Fort McMurray Zama Norman Wells Edmonton Blaine Portland Salt Lake Casper Cushing Houston New Orleans Montreal Toronto Sarnia Calgary Fort St. John ENBRIDGE INC. Headquarters: Calgary, Alberta, Canada ENBRIDGE ENERGY PARTNERS, L.P. Headquarters: Houston, Texas, U.S.A. ENBRIDGE GAS DISTRIBUTION Headquarters: Toronto, Ontario, Canada Liquids Systems and Joint Ventures Natural Gas Systems and Joint Ventures Power Transmission Natural Gas Distribution Solar Assets Wind Assets Geothermal Assets Waste Heat Recovery Growth and Execution > 13 ENBRIDGE: A KEY PLAYER IN A CHANGING NORTH AMERICAN ENERGY LANDSCAPE We rman ma o No e orm ls lls ell Za Zam am ama m Fo St Fo F urr rra ort oh rt o Jo hn rt Mur Mc ray cMu t. ay Ed on ont o dmo d Edm to i Ha ty rdi ardist dis Bl i ine aine ary a g la ga lg Bla Ca Calg ry Po Portl and ort d la tla pe p Supe or i e o io upe peri Su tr u rio tre re r o Mo ea e rea nt n al Mont o To T Ca er e per spe Cas asp t ro ront n ont nto to Toro r or Ci City e ke nia Sarn rn Sa La ty t L Cit ake alt i Sa ia To e ledo do i go Ch o d ed g ag ole Chica cag hic Pa P to Pat ka oka ato Ri er Wo Woo o v Riv iv ood oo ve ive od o Cu i sh ng n in us hi Cus O Ne N ns n ans an e Orl ea e lea s rle w a to ous o Ho ton ust S A l V i J d i t t C BR D i e d r t t s s s e e e o o n n n r m G q S s s s s a a L u u . N I E I N E y l H r r a e d b g t : a e e q n r rs a a a A d C C G u a a a i i l r ss e t t n l t , , s e a a e e o m n nd n t r y s a A d J S s s s a V W u t u t N y PA B D S R R R E R Y G A A P N i i , G L E E E E m m e o o Tr T r . N RT I N s a e e e o h n n t r s s s s s a G t l w S H s e Te T o t : s e e o n r r x H a A q d U s a a . . . t u u , , D N R i i i e r r bu s s e e e o on r G a a a c s a a v t H t W t t l u t S O B B D D y A R R G G S U N E N I T I T I E I O C i To r a n n o o o r r d t n r : e e o d s a a q a a a t t u H , ,

We’re investing in tomorrow’s energy, today. BUILDING THE FUTURE ENERGY ECONOMY 14 < ENBRIDGE INC. 2012 ANNUAL REVIEW R R UILDIN FUTU E ENE Y E N MY B G G CO O

WHAT WE’RE DOING TODAY Enbridge is actively participating in society’s transition to a lowercarbon intensive economy. Since our initial investment in a wind farm in 2002, we’ve invested approximately $3 billion in wind, solar, geothermal, waste heat recovery, and a host of other alternative energy technology projects that, together, have the capacity to generate more than 1,300 MW of emissions-free energy. And we’re not stopping there. We started mapping out Enbridge’s journey into renewable and alternative energy generation more than a decade ago because we believed it was in the Company’s strategic interest to examine emerging technologies and to be ready for them. We’ve now grown to the point where today, in Canada, we’re the largest solar energy generator and the second largest wind generator; and we’re also a growing player in the United States with wind, solar and geothermal investments. All of our projects are underpinned by attractive long-term power purchase agreements and fixed-price contracts, delivering stable cash flows and attractive returns. While the majority of Enbridge’s renewable energy investments are in wind and solar energy projects, the Company also invests in other technologies, projects and companies that will achieve returns similar to those realized by Enbridge’s oil and gas transportation and delivery operations, and that will contribute to a cleaner energy future. We plan to double our green energy capacity in the five years from 2011 to 2016. This is one of the ways we’re laying the foundation for a more diversified asset base and continued growth and prosperity for the Company. In addition to contributing to a cleaner energy future, our green energy investments are a key component of Enbridge’s plan to achieve a neutral environmental footprint as we grow our operations. We’ve already pledged to generate a kilowatt hour of renewable energy for every kilowatt hour of additional electricity that our operations consume. To learn more about our Neutral Footprint program or for quarterly updates on our progress, please visit our online dashboard at enbridge.com/neutralfootprint OUR RENEWABLE ENERGY INVESTMENTS WIND Our 10 wind farms—in Quebec, Ontario, Saskatchewan, Alberta and Colorado—have the capacity to generate nearly 1,170 MW of electricity. In late 2012, we announced Enbridge will invest approximately $170 million to acquire a 50% interest in the 150 MW Massif du Sud Wind Project in Quebec. Wind is the fastest growing sector of electricity generation in North America. We expect future wind opportunities to come through expanding our existing operations and developing new greenfield projects throughout North America. SOLAR Our four solar energy projects—in Ontario and Nevada—have the capacity to generate 150 MW of electricity. In 2012, we completed and put into service our first solar farm in the United States—our wholly owned 50 MW Silver State North Solar Project in Nevada. Our 80 MW Sarnia Solar facility in Ontario is one of the largest photovoltaic solar energy facilities in North America. Enbridge believes that solar energy represents meaningful opportunities for long-term growth. 410,000 HOMES/ 1.6 MILLION TONNES Enbridge’s interests in renewable and alternative energy generation, both in operation and under construction, have the capacity to supply the equivalent of almost 410,000 homes with energy and result in the avoidance of approximately 1.6 million tonnes of greenhouse gas emissions each year. Pictured to the left is our Sarnia Solar facility in Ontario, which is one of the largest photovoltaic solar energy facilities in North America. csr.enbridge.com/greenenergy Building the Future Energy Economy > 15 1 4 O 0 0 ES 0 0 , M H / O 6 TO M L L . E N N N I I 1 l i ’ i t i s s n n n n n e e e e g e e t r r r b b d d a s a w E i i r r rn e o on n t n h e e e e g g e t a b a a t t v l , y i i i r c n n o o o o e t n n n n p d e t r r a a d uc s u ti , h t i a a s p he e o e v c h p p c a u t t t l y y l i 00 0 0 a o o o m h n me e e f 4 a q s s t t 1 l v u , i h i l i n o r n n ne t s g e d h e e e r a d c a a u t t v w y i f f i i p m n n m e e p o o o o o 6 s n t r a a . t l l 1 l x y i h i r. s s m o o e e e n h e g g n e e r c a a a s s s u y l i P i i r r r e o o o c n t h a d e e r S Sa a s t t t u f l u O i i i i i i c n h n o o o h e n t e h f r c a a s w t t l f , y i t r r r s n c e e o o o o p a h g ge a a s t t l l v l y i f i i i i A c m o h n e e rt t r c s a a . N l

INVESTING IN INNOVATION “ Since 2000, Enbridge has been steadily increasing our investments in clean energy projects, such as wind and solar. In addition, we also invest in other emerging technologies, projects and companies that will contribute to a cleaner energy future.” Chuck Szmurlo, Vice President, Alternative & Emerging Technology, Enbridge Inc. GEOTHERMAL We’ve taken a first step into geothermal power generation through our 41% interest in the 35 MW Neal Hot Springs Geothermal Project in Oregon, which became operational in November 2012. Geothermal power, which is recovered from the heat of the earth’s interior, supplies just 0.3% of the world’s energy needs, but proponents hope to see that figure climb to anywhere from 10% to 20% by 2050. OUR INVESTMENTS IN ENERGY INNOVATION In addition to investing in renewable energy projects, we’re also searching the world for, and investing in, new technologies and businesses that are strategically aligned with Enbridge’s business interests. WASTE HEAT RECOVERY We’ve invested in four waste heat recovery facilities that harness heat produced by Alliance Pipelines’ gas turbines and generate approximately 20 MW of power. In 2013, a fifth waste heat recovery unit is scheduled to be put into service at Alliance’s compressor station near Whitecourt, Alberta. It will deliver up to 14 MW of electricity. ELECTRICITY STORAGE As society generates more renewable energy, industry needs to find a way to store the electricity during non-peak demand hours. That’s why we’re investing in technologies that support large-scale electricity storage. In 2012, Enbridge entered into a partnership with Hydrogenics Corporation, whose water electrolysis technology will convert surplus renewable energy into ultra clean burning hydrogen gas. Enbridge’s expertise in the ownership and operation The opening of our 50 megawatt Silver State North solar plant in 2012 marked Enbridge’s entry into the U.S. solar energy market, which presents significant growth opportunities given the excellent solar resources and supportive regulatory environment. Don Thompson, Vice President, Green Energy, Enbridge Inc. csr.enbridge.com/pathfinders 16 < ENBRIDGE INC. 2012 ANNUAL REVIEW G O S AT V O E N I AT N N I N I N I T N I i b 00 0 i e n h n n e b dg e e r S s c a 2 E , i i i i s m n n e e e o n n s e g r r ad s s c a t t t v u l y i j i s g o r r h e n n s c e d n n e ec p a a s c w t u l , y i I l t i i i r. s n o o o n n n e d n e d d s a a a a s w t v l , i l i j r s o ro o o o p n h m th n c c g g g e e e e e e t t r r s , i i t i n b e o o h n c n m e r p d c a a a s w t t t u l l ” f r o e e e n n e g e r r c u a . t tu l y l C i i V P r o h c e d m z s n e e r S c t u k u , , i i c n n m Te e o o n h g g g e er r A a v E t l T lt , y d i nbr n ge c I E .

of natural gas pipelines will enable the partnership to offer seasonal electricity storage capability to the electricity sector. The two companies will jointly develop a 1 MW power-to-gas energy storage project in Ontario to prove the technology at a utility scale. The technology could be particularly advantageous in markets with large amounts of renewable energy from intermittent sources, such as wind. By converting electricity to gas and storing it in vast natural gas pipeline networks, more renewable energy can be stored for long periods, increasing the amount of clean energy that can be generated and made available for consumers. In early 2013, Enbridge made an equity investment in Temporal Power, an Ontario-based developer and manufacturer of electrical energy storage systems. Their proprietary “flywheel” technology enables utilities, electricity generators and industrial customers to realize the benefits of large-scale energy storage with a low cost, high performance solution. We believe Temporal Power’s technology is world leading and offers attractive opportunities to deploy electricity storage plants around the globe, thus enabling the growth of intermittent renewable power sources. MORGAN SOLAR We’ve invested in Morgan Solar, a Canadian start-up company, to help them commercialize their nextgeneration solar technology that boosts the power output of solar cells, thereby generating solar power more efficiently, less expensively and with a lower environmental footprint. RUN OF RIVER HYDRO Enbridge has invested in the Wasdell Falls Run of River Hydro Project on Ontario’s Severn River that will generate hydroelectricity using highly efficient turbines. Designed to create lower impact installations, the turbines require less infrastructure than traditional run-of-river projects. LOWER-CARBON-IMPACT SOLUTIONS While the world is gradually developing more alternative energy sources, the fact remains that the world will need petroleum and other fossil fuels for decades to come. Given this reality, we know that moving hydrocarbons will be Enbridge’s core business for a long time, so we’re evaluating and investing in technologies designed to lower the environmental impact of hydrocarbons. LEAK DETECTION AND RISK MITIGATION TECHNOLOGIES In addition to our ongoing safety and system integrity improvements, we actively seek out world-class leak detection and risk mitigation technologies that we can apply to our operations. Innovations that we’re evaluating and investing in include: real-time leak detection technologies; ultra-high-sensitivity gas-leak monitoring systems; advanced aerial leak-detection technologies; gas-sensing technology for use on above-ground storage tanks; and leak-response technologies. For more information, please visit csr.enbridge.com/innovation SMART ENERGY GRID “ We need a smart energy grid, rather than a smart electricity grid, so that surplus energy from wind or nuclear can be physically moved to the gas grid. Then you can store it, and do a lot of things you can’t do if you keep it as electrons in the wires. The moment you store it, you have all kinds of flexibility. Pipelines are, by far, more costeffective vehicles to get renewable energy to urban centres than wires; it’s a basic fact. ” David Teichroeb, Business Development, Alternative & Emerging Technology, Enbridge Inc. enbridge.com/smartenergy Building the Future Energy Economy > 17 S R A R R Y G G I E N E T M i r m n n e h e e d g g e e e r r r d a s a t rt W , y i i i r m o c h h c g n d e e t r a a a s s t t rt t t l , y i f r m o o r n u n s g n e e e r r r p d u a s c w u l l y h i b m h e e e o o p a a g n t d c c as s t v l l y y l d d i i an n o o o o n s d g h e re e t r c a . t t u T , y i i f f t i ’ a d h e e o o o o n a ng t p c s s t k u u y y h i i s n h o o o ro m r n n m e e e e e e t r c . s w t t u T l y i f t i i i i s n h o o o e e e f r x b d a a s t t y. l l k l l v u , y y f i Pi r, r s m e o o c n e e e t r - b p a a s l i , y l b i ff i s n h o e e c e e e e e e g e t r c a t t w l v v ir n e e o n s s h g n n e e re e t r r r w ; c a b a t t i u y ’ f t i i a b c s s a c t. D i i l B D ro i b s ne e o h e d e Te v c s s m n e e a p u T v t, , l i l in m Te e g e o o r n h g g n e r E A c a v t i t , y I i n b e ri g n c d . E

We’re delivering the superior returns that our investors have come to expect. SOLID INVESTMENT 18 < ENBRIDGE INC. 2012 ANNUAL REVIEW S O S T N E M T E V N I D

INDUSTRY LEADING GROWTH In response to evolving North American energy fundamentals and the needs of our customers for access to new markets, we’ve received customer support and are moving ahead with $27 billion of attractive investment opportunities. These commercially secured growth projects will drive significant earnings and cash flow growth over the next five years and beyond. As we develop new business platforms, we’re confident we’ll extend our industry-leading growth rate throughout this decade. One thing our shareholders know is that Enbridge consistently creates value for them. Enbridge’s total shareholder return (TSR) has outperformed the S&P/TSX Composite Index over the past 10 years with an average annual return of 19% compared to 9% for the Composite Index. In 2012, we achieved a TSR of 16%, more than double the TSX Composite Index’s performance. We credit Enbridge’s proven value proposition—visible growth, a reliable business model and growing income stream—for delivering such excellent returns to shareholders over so many years, and we plan to stick with our proven formula. VISIBLE GROWTH All of the energy infrastructure projects we’re developing are supported by strong supply and demand fundamentals and are highly strategic both for our customers and the North American economy. With $27 billion in growth projects already secured and anticipated to come into service by 2016, we expect to achieve the high end of our 10% – 12% average annual adjusted EPS growth guidance range over the next five years.1 RELIABLE BUSINESS MODEL A substantial amount of Enbridge’s earnings come from fees paid by customers for essential energy delivery services. As a result, our business model produces adjusted earnings you can count on. We have a consistent track record of meeting our earnings guidance. Our guidance range for 2012 adjusted earnings was $1.58 to $1.74 per common share and we delivered $1.62 per common share. We expect 2013 will be another strong year for adjusted earnings growth. Our guidance range for 2013 adjusted earnings is $1.74 to $1.90 per common share. A 12 11 10 09 08 07 06 05 04 03 02 ENB 19% S&P/TSX 9% TOTAL SHAREHOLDER RETURN* 2012 was another rewarding year for our shareholders, with total shareholder return (TSR) reaching 16%. Over the past 10 years, our TSR has outperformed the S&P/TSX Composite Index on average by 10% per year. The key ingredients to sustain this track record remain in place—visible, transparent and sustained earnings and cash flow growth along with a substantial and growing dividend, all while maintaining a reliable business model. * Compound annual growth rate 2002 – 2012 ADJUSTED EARNINGS PER COMMON SHARE* (Canadian dollars per share) We’re confident we can achieve 10% in average annual adjusted EPS growth through the middle of the decade. * Financial information for 2010 through 2013 has been extracted from financial statements prepared in accordance with U.S. GAAP. Financial information from 2003 through 2010 has been extracted from financial statements prepared in accordance with Canadian GAAP. 0.75 0.74 0.80 0.87 0.90 0.94 1.18 1.32 1.46 1.62 13e 12 11 10 09 08 07 06 05 04 03 1.74 – 1.90 Adjusted earnings and adjusted earnings per common share are non-GAAP measures that do not have any standardized meaning prescribed by generally accepted accounting principles. For more information on non-GAAP measures, see page 28. Solid Investment > 19 1 O D * R R R S E R E A A TA U O L N T E L H H TA T N E B % 9 f 0 i o o r r h e e re n s e d g n r r a a a a w 2 t w 1 2 y l i r r a a d h o o o o h h e h h e e e r r r d a s s s t u t t l w l , O i h % R) 6 r a n n c r t h e re e g e re e S p s a . t t v 1 u T R 0 1 t m e o o o h p h e e e r r rf rs a d S as s t u T u , y d i P & s o o o r n t x n a m ge e e e C S p S av I X /T i i % 0 n e e k h p n e g e e e r r r b d s a t T r. 1 y y y i i i r s o o r e re e re h n n c m t t r r k d rd c a a a s s t u t i i i r s a n n b p re n e e d n t a a a p — s c t l v l , l i i f a a a a h e e o c n n n s g d n r d s s s t w u t i i d n o o r n g g h n h t a b u a s a a s t t l w l w i l l i i i i i i r e o n n n n h m g g g n d e t a d d a a w w v l , i ia d o u re n m e b e e e b s s . s 1 0 0 8 l l i l 7 2 9 6 3 0 0 0 0 0 0 0 4 5 1 1 i i ’ h o e n n c n e e e e e t r a a d W c c v w f j i % 0 r n e e v n n ge t a d d a s a a a u l u 1 l h P i m o o r g d g h h h e e t t r E d u S wt d h a d c o t e e e f .

GROWING EARNINGS STREAM Our growing earnings provide a solid base for continued dividend growth. We’ve increased the dividend in each of the last 18 years and over the past 10 years have delivered average dividend growth of 12%. We increased the dividend by 15% in 2012 and have announced another 12% increase to the dividend payable on March 1, 2013. We expect that our industry-leading earnings growth will translate into similar levels of dividend growth over the next five years. ENSURING OUR FINANCIAL STRENGTH AND FLEXIBILITY Maintaining adequate financial strength and flexibility for Enbridge is fundamental to the execution of our growth strategy. We’re focused on developing and executing financing plans and strategies that maintain our credit ratings, diversify our funding sources and provide substantial standby bank credit capacity and access to capital markets in both Canada and the United States. Our capital market activity in 2012 was considerable: Enbridge was the fourthlargest issuer of capital market securities and the third-largest issuer of equity securities in North American markets. We’re the largest issuer of rate-reset preference shares in North America. We issued $2.7 billion in 2012 alone, and have issued $3.7 billion since July 2011. With a 4% yield, this is a very low cost and attractive source of capital for us. Our funding and liquidity actions in 2012 were directed not only at keeping up with a record year of growth investments in 2012, but also at building additional liquidity and equity reserves to support the substantial growth program ahead of us. We’ve taken prudent actions to get ahead of the curve, and while our decision to pre-fund a significant amount of equity, primarily in the form of preference shares, had a slight impact on our earnings per common share in 2012, we still delivered an impressive 11% year-over-year growth rate, which was well within our guidance range. Our sponsored investments—Enbridge Income Fund (the Fund) and Enbridge Energy Partners—provide us with supplementary sources of debt and equity funding. For example, in 2012, Enbridge transferred a group of crude oil storage, wind power and solar power assets valued at $1.2 billion to the Fund, a transaction that provided $800 million of net funding for Enbridge’s growth investment program. SUSTAINABILITY RECOGNITION “ An increasing number of shareholders are looking to invest in sustainable and socially responsible companies. Enbridge’s strong commitment to sustainability has resulted in the Company receiving recognition for our ability to deal with key social and environmental factors while also delivering the best returns for our shareholders. In January 2013, Enbridge was recognized as one of the Global 100 Most Sustainable Corporations in the World. Enbridge is also listed on the Dow Jones Sustainability Indices (World and North American), the Financial Times/London Stock Exchange ( FTSE4Good Index), and the Carbon Disclosure Project’s Leadership Index, which highlights companies that have displayed a strong approach to non-financial performance and information disclosure.” Paul Hunt, Director, Sustainability & CSR, Enbridge Inc. When you combine Enbridge’s record slate of attractive growth projects with the current record low cost of capital, you get our industry-leading adjusted earnings-per-share growth rate and substantial valuation upside. Richard Bird, Executive Vice President, Chief Financial Officer & Corporate Development, Enbridge Inc. 20 < ENBRIDGE INC. 2012 ANNUAL REVIEW S U B R C N Y A A TA S O G O N I T I N E T I L I I l i t i i i i sh o o o o o r r r r n n h n n e n s n m g g e e e n e e f r k A a b d c a a s s t v l u i l i i i i ’ r s s b d m e e e e p o o o n n r n n s s s s n b g e c a b p d u a a a c a . s t E l l l y h i i i i i r a m m m m n o o o o h n n t s p d g n n e e e e r c b C u a a a s s s s t u t t t t t t l l y y i i i i i i i i r r a n e e o o o o o on c n g g n h e e e t r r k b d d c c a a a s t v t t l w l l u f y y i l l i f i i s s s a h o ro o o o re e h n r n m b n n e g d n e e e e e e t t t r r r r c a a s w t t u v l f l v i i J 0 3 r re a c b e e o o o n n h h n n s s e e d g g d e r r r E a a d u a a s. s 2 z u w 1 I l , ry C l 0 0 t i i i s h o o o o o o o r e n t n n n b h e e e r a a a S p b a s s t t t l u M 1 l G f D S i i i i i i s b o o o o o r r n n w h n g e e n e e b d d d J a s a a . s s s t t t t l u l l E l W y d W ) Ti i i Fi i i A s m n h n in o o o o c n n n n a e c e e im h d e r r a ia a d d ca s rt L t l N l I / , d D x) i 4 r d n o o o o o c c n n n C h s g b e e h e e t r F E k d S u S c a a a s E t l I G T x , i ’ j P i i i i r s d h e e e e o o h h h n h h n h m e g g h e t t r x c a p p d a s c c a a s L t t v l w I s , i f i i rf r ro d c m n h o o o o o p p t n n n n p p d d g n n e e e r c - a a a a c a a s a s t l l y i i t i ” r m e re o o o c r n s n f a d . s u l P i i D t C R a n i i i n e b b or u n g n e t r r a S d S c a c s E t I l u H l u . , t , , y

FINANCIAL HIGHLIGHTS Year ended December 31, 2012 2011 2010 (millions of Canadian dollars, except per share amounts) Earnings per common share 1 0.79 1.09 1.27 Adjusted earnings per common share 1 1.62 1.46 1.32 Dividends paid per common share 1 1.13 0.98 0.85 Common share dividends declared 895 759 648 Return on average shareholders’ equity 6.3% 11.3% 14.1% Debt to debt plus shareholders’ equity 67.1% 72.9% 73.7% OPERATING HIGHLIGHTS Year ended December 31, 2012 2011 2010 Liquids Pipelines—Average deliveries (thousands of barrels per day) Canadian Mainline 2 1,646 1,554 1,537 Regional Oil Sands System 3 414 334 291 Spearhead Pipeline 151 82 144 Gas Distribution—Enbridge Gas Distribution Volumes (billions of cubic feet) 395 426 409 Number of active customers (thousands) 4 2,032 1,997 1,963 Gas Pipelines, Processing and Energy Services— Average throughput volume (millions of cubic feet per day) Alliance Pipeline US 1,553 1,564 1,600 Vector Pipeline 1,534 1,525 1,456 Enbridge Offshore Pipelines 1,540 1,595 1,962 Renewable and Alternative Energy 2,334 687 1 Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011. 2 Canadian Mainline includes deliveries ex-Gretna, Manitoba, which is made up of United States and eastern Canada deliveries originating from western Canada. 3 Volumes are for the Athabasca mainline and Waupisoo Pipeline and exclude laterals on the Regional Oil Sands System. 4 Number of active customers is the number of natural gas consuming EGD customers at the end of the period. CENTURY BOND “ In July 2012, our subsidiary, Enbridge Pipelines Inc., successfully issued a $ 100 million Century Bond with a 100 year term to maturity, a clear demonstration of the investment community’s confidence in the longterm sustainability of Enbridge’s business model. This is only the second Century Bond ever issued by a Canadian corporation.” Colin Gruending, Vice President, Finance & Tax, Enbridge Inc. Solid Investment > 21 Power generated (gigawatt hours) 1,248 O N B D R E Y C U N T b E i I 0 2 i i d d o r r n n ge b Ju s a su u 2 1 l y, , y ry, I i P i i s n p s s n e e e e f c d s c c. s s u u l l u l , y l B 00 t C i i i h o o n n 1 m d n e t u w l ry i 0 0 r a m e o c r 1 m e e t t t r r a a t l u y, y i i r s m o o o e n m n n e e n h e t f t d a s v t t t l i i i ’ mm n c n e e e o o o h n n n s c g t - d c t f u y i f i i i ’ m o r n g d n e e t r a b b s s a s t t E l u y i i i m h o o n h s s e n e e b d s . s s t l T l u y C B i d n n e e o o n u s e b d d e e r s s c v u t y ry i i ” r o o o n C p d n n ra a c a a t . i C i i P i n o g d n n e r n r s de e e c u V G l t, , I b E i i c r n n g n n e e c F d a Ta . x ,

Whether it’s delivering energy or delivering returns for our investors, we hold ourselves to very high standards. LETTER TO SHAREHOLDERS 22 < ENBRIDGE INC. 2012 ANNUAL REVIEW HA H L L ETTE T E E R R R D O O S S A

AL MONACO AND DAVID ARLEDGE Al Monaco President & Chief Executive Officer, Enbridge Inc. David A. Arledge Chair of the Board, Enbridge Inc. Letter to Shareholders > 23 These are times of significant change, challenge and opportunity for the energy industry. Over the past year the management team at Enbridge has been focused on executing strategies and priorities to meet those challenges and position our Company for the future. We would like to begin by recognizing the significant contribution of Patrick Daniel, who retired as Enbridge’s Chief Executive Officer in September of last year. Pat was an exemplary leader and his legacy will endure in our ongoing commitment to meeting the needs of our customers and in our unwavering commitment to social responsibility. We wish Pat well and we thank him for his dedication to our Company. HOW WE APPROACH THE BUSINESS In light of the change in Enbridge’s leadership last year, we believe it’s important to reiterate our principles and approach to the business. We’re proud of that business model and it won’t change. Safety and operational reliability Nothing is more important to us than the safety and operational reliability of our systems. This is our number one priority. Our value propositionWe believe that the combination of our reliable business model, industry leading growth and dividend income payout will continue to generate superior returns for our shareholders. Our strong customer focus We’re driven to find value-added solutions for our customers—if we do that well, we’ll deliver value for our shareholders. Our investment discipline We’re focused on largely organic growth and small to medium-sized acquisitions that enhance our strategic position, rather than large scale transformational transactions. Our commitment to preserving financial strength and flexibility We’re a capital intensive business with significant growth ahead of us so it’s critical that we maintain good access to capital and ample liquidity. Our attention to developing our people We’re focused on developing people at all levels of the organization. Our practice of rotating management ensures we have a broad base of decision-making experience across our organization. Our responsibility for the sustainability of our business We will continue to lead in the development of renewable energy so that we can play a significant part in the transition to a lower carbon intensive economy. This approach to our business has been key to Enbridge’s accomplishments over the years, and will continue to be central to the Company’s success as the energy industry experiences profound change. A LOOK AT 2012 2012 was another strong year for our Company, with adjusted earnings per share (EPS) of $1.62, an 11% increase over 2011. This was in line with our expectations and historical growth rate. With the new capital investments we secured last year, we’re confident we can continue our track record of industry leading growth for many years to come. Based on these strong results, and the Board’s confidence in our long-term outlook, we increased our first quarter 2013 dividend by 12%—the eighteenth consecutive year in which we’ve had a dividend increase. 2012 was also our most successful year ever in terms of new business development. We secured approximately $14 billion of new growth projects, bringing our total inventory of commercially secured projects to $27 billion. We continue to be steadfast in our disciplined capital review and investment process, with a focus on projects with strong business fundamentals and commercial underpinning. This past year was not without its challenges. Persistent low prices for natural gas and deteriorating natural gas liquids pricing hampered our gathering and processing operations. We also wrote down the value of part of our Gulf Coast offshore assets. While this was a disappointment, the business is stabilizing O D A A A C O N N M L D D D R A AV GE E L I n o o c A a M l i P C i i i r n c c e t e e e e e t h r E O d s f ff f v u x f r, I i n r g n e d E b c. i Da A r e e g d d A l . v i B E i n e h d o o r n e g d h r r a b C c a t . I f ,

24 < ENBRIDGE INC. 2012 ANNUAL REVIEW and with new contracted projects coming in to service in 2014, we anticipate returning to profitability in this business. Our growth profile and business model have consistently translated into value for our shareholders and in 2012 we achieved a total shareholder return of 16%, well in excess of the broader market. Enbridge’s average annual total shareholder return of 19% over the last 10 years was more than double the return of 9% delivered by the S&P/TSX Composite Index over the same time period. All the key ingredients to sustain our track record remain in place. THE ENERGY LANDSCAPE IS CHANGING Over the next decade, global growth in energy demand will not be driven by North America or Europe but rather by emerging markets—especially Asia. At the same time, U.S. oil consumption is expected to be more or less flat due to slower economic growth, increasing fuel efficiency, the use of biofuels and changing demographics. It was only a few years ago that North America was facing declining oil production and the need for increased imports of oil and natural gas. However, today the continent is on the road to energy self-sufficiency. U.S. production is forecast to double to 12 million barrels per day (bpd) over the next two decades, and Canadian oil production is expected to double to 6 million bpd over that timeframe, putting Canada in the top four oil producing nations globally. What’s driving such a dramatic turnaround? The oil and gas industry has unlocked massive unconventional reserves—through horizontal drilling, new reservoir stimulation methods and economies of scale. The robust outlook for oil and gas production growth is resulting in significant transportation bottlenecks between growing supply regions and both continental and global markets. There is well-developed pipeline infrastructure, but there’s not enough of it, and it’s not in the right places. Without good connectivity, the result is significant regional price disparities and reduced prices for Western Canadian and Bakken crude. WE’RE CREATING LIQUIDS PIPELINES MARKET ACCESS SOLUTIONS We believe that the industry’s biggest challenge is gaining access to new markets, which in turn is driving our strategy. Enbridge recognized the importance of these market access challenges some time ago, and we’ve been responding aggressively. We’ve embarked on the largest capital program in the Company’s history—$27 billion of commercially secured growth investments across all our business segments. All of these projects are planned to be in service by 2016. In our Liquids Pipelines business various market access initiatives will open new or expanded markets for about 1.3 million bpd of crude oil beyond the Chicago market hub. Our immediate emphasis is on opening pathways to the Gulf Coast and the east coast of the U.S. and eastern Canada. That’s in addition to all the regional pipeline development we’re undertaking in the Alberta oil sands and the Bakken area, where we are very well positioned. In 2012, Enbridge announced the upsizing of our proposed series of projects designed to connect Canadian oil to western U.S. Gulf Coast refineries that are configured to take Canadian heavy oil and eager to receive it. A portion of this program is already in place, and by mid-2014 we expect to add approximately 585,000 bpd of capacity out of Chicago, matching up with the in-service timing for the Seaway Twin connecting Cushing to the western Gulf. We’re also developing a project that would, for the first time, provide direct pipeline access for heavy and light crude to the eastern Gulf Coast from Canada and the midwest U.S. We’re expanding and extending our path for new crude oil production to the eastern part of the continent, including the U.S. midwest refinery market and eastern Canada. Our Eastern Access program will allow barrels to reach these markets that are currently dependent on high cost crude oil that is pricing off the global benchmark. This program will level the playing field for Canadian refineries, protecting their long-term viability and safeguarding jobs. We’re advancing projects that will serve to connect growing light oil supplies from the Bakken play in North Dakota, and from Western Canada, to premium refinery markets in Ontario, Quebec and the U.S. midwest.

EXECUTIVE LEADERSHIP TEAM (left to right) D. Guy Jarvis President, Enbridge Gas Distribution Leon A. Zupan President, Gas Pipelines David Robottom Executive Vice President & Chief Legal Officer Janet A. Holder Executive Vice President, Western Access J. Richard Bird Executive Vice President, Chief Financial Officer & Corporate Development Al Monaco President & Chief Executive Officer Stephen J. Wuori President, Liquids Pipelines & Major Projects Karen L. Radford Executive Vice President, People & Partners Letter to Shareholders > 25 We believe that these projects will go a long way to addressing the significant pricing discounts that producers are currently facing, as well as to meet the demand of North American refiners seeking reliable domestic supply. To offer Canadian producers further optionality and to connect growing supply with robust Asian demand, we continue to move forward with the Northern Gateway Project to move crude oil from Alberta to Canada’s Pacific Coast. Northern Gateway would be a significant step towards achieving market diversity and global pricing for Canada. WE’RE GROWING OUR OTHER CORE BUSINESSES While the bulk of our growth right now is in our Liquids Pipelines segment, our other businesses are growing as well. We are completing the Texas Express Pipeline, which will secure long-term access for natural gas liquids to the premium market at Mont Belvieu, Texas. We have been successful in capitalizing on the liquids rich gas plays that we’re seeing in North America right now. With our interests in the Alliance Pipeline, which originates in the heart of the Montney and runs past the Bakken, and in the Aux Sable processing facility near Chicago, we’re going to be able to provide very attractive offerings and access to premium markets for our customers. In 2012, we advanced our Canadian midstream natural gas strategy with our acquisition of the Peace River Arch assets in Alberta’s liquids-rich Montney play, and we look forward to leveraging our position there. We announced the single largest capital project in Enbridge Gas Distribution’s history—the approximately $600 million expansion of our natural gas distribution system in the Greater Toronto Area. We also added the Heidelberg crude oil lateral to our expanding list of attractive new Gulf Coast offshore projects. Our green energy power generation business continues to grow with the completion of our Silver State North Solar Project in Nevada, the start-up of the Neal Hot Springs Geothermal Project in Oregon and our investment in the Massif du Sud Wind Farm in Quebec. We see renewable energy playing an increasingly prominent role as our North American energy economy moves to a lower liquids-hydrocarbon intensity over the next few decades. Our first power transmission project is targeted to go into operation in the second quarter of 2013. The 300- megawatt Montana-Alberta Tie-Line Project is a 345-kilometre transmission line from Great Falls, Montana to Lethbridge, Alberta. WE’RE FOCUSED ON THREE KEY PRIORITIES Even though we’ve had great success in the past, we need to continue to evolve and get better at what we do to meet the changing landscape of the energy industry. Three key priorities underpin our strategic plan going forward: our safety and operational reliability; execution; and extending our growth rate. SAFETY AND OPERATIONAL RELIABILITY The safety and operational reliability of our systems is our highest priority. While we have always focused on these areas, we have re-set the performance bar, striving for no less than industry leadership. The July 2010 spill in Marshall, Michigan has had an enduring impact on our Company. We made a commitment to do whatever it took to make things right in the community and we were pleased to see the Kalamazoo River reopened for recreational use in the summer of 2012. We also committed to fully understand what had happened and have been working with all parties, doing what was necessary to improve procedures, our facilities and technology so that an incident like this will not happen again. The National Transportation Safety Board released its findings last year with respect to the cause of the Marshall accident. Our own efforts to implement numerous enhancements and improvements however, began more than two years ago with incremental initiatives in pipeline safety and integrity, in leak detection, in control centre training and procedures, emergency response protocols and in public engagement and awareness programs. We’re making significant investments in new technology and innovation with particular emphasis on inspection tools and leak detection. C P D R X A A S U E M E T I H E E L E V I T E i R Bir r i d d ha J c . P t i i i n cu e e e e e r x D d i c s E t V v rv , Ja G s u . y O i F C ff i i i a r h n c n e e i P D i i i i c a d s e r g n e e t r n n r l f E Ga b b d o s s t t u , C D t m n e o o v e e e p r r p o a l t Z n p eo A an L u . o A n o ac i P P i i s r e e p n e e n M l Ga d s s t l , P O i i i i h r n e e d r e e e e x C cu s c v ff t E f t i D R t T. d ob m o o a t v i n r t e eph i P o i i J S W . e e u s e e e d t r n x E c c t V v u i i P P i i iq s n d s e e e e d t r n O C f i p i s a e e e g h r l u i L , c ff l L P j j aj s r o ro c e t M d l J r e e o n H A a . t K f d d r e R o n r i P a i i n e c a u e e e e d r . L c E s t V v t x , i P i i r c n e e e e e c d s t r t V E t s e e We e n v u x , c Ac s s P P r o r e e e n p a s t l

OUR PRIORITIES ARE CLEAR We will establish Enbridge as an industry leader in operational reliability, excellent safety and environmental performance. We will focus on executing our secured capital investments to drive significant earnings and cash flow for our 26 < ENBRIDGE INC. 2012 ANNUAL REVIEW shareholders over the next five years and beyond, and provide value added solutions for our customers. We’ve also further strengthened executive oversight of safety with the creation of the new role of Senior Vice President, Enterprise Safety & Operational Reliability. This role, which reports directly to the CEO, is accountable for defining and executing on an enterprise-wide vision, culture and set of integrated programs and policies. Our goal remains focused and unwavering: to be the industry leader across all of the key dimensions of operations and safety. EXECUTING OUR CAPITAL PROGRAM We’re focused on executing our strategic plan—if we can do that well, we’re confident that we can deliver industry leading growth. Given the size of our secured capital program, effective project execution will be central to assuring our success over the coming years. We need to get projects completed safely, on time and on budget. In 2012, we brought four projects on line, all on time and all below budget, and we’re in excellent shape to bring 17 more projects into service this year. An equally critical part of execution is ensuring that we have enough funding to make these projects happen. We have good access to capital with attractive funding costs, which stems from our solid business model and our strategic position. Our actions to date position us very well to meet our funding requirements through 2016. Successful execution also rests on the dedication and talent of our employees. To support our commitment to operational reliability and help deliver our growth projects, in 2012 we added approximately 1,500 people to our team enterprise-wide in Canada and the United States. Our projects create thousands of construction jobs in communities across North America, generate hundreds of millions of dollars in labour-related income, and create additional permanent jobs when the projects come on stream. As we grow, we remain committed to sustainability and to our Neutral Footprint program—we are right on track with our goals of planting a tree for every tree we remove, conserving an acre for every acre we permanently impact and generating a kilowatt hour of renewable energy for every kilowatt hour of additional power we consume. EXTENDING OUR GROWTH BEYOND 2016 Finally, while our medium-term outlook looks excellent, we’re also strengthening our core businesses and building new investment platforms so that we extend growth well into the future. Going forward, we expect to see an increasing contribution from new growth platforms including Canadian midstream natural gas, electric power generation and transmission and international. Building these new platforms helps to diversify our sources of earnings growth in businesses that fit very well with our existing investment proposition. A POSITIVE OUTLOOK The energy marketplace is undergoing profound and transformative change and Enbridge is in the midst of that change. As we grow, the safety, reliability and environmental sustainability of our systems will always come first—it is the foundation for everything we do. Our assets are extremely well positioned to expand and to extend into new markets, enabling us to create value for our customers and our shareholders. Based on the number of opportunities we were able to secure over the course of the year, and the opportunities ahead of us, we have confidence that we will be able to maintain our industry leading growth through 2016 and well into the latter half of the decade. DAVID A. ARLEDGE AL MONACO Chair, Board of Directors President & Chief Executive Officer March 8, 2013 We will continue to build our business by developing new platforms—midstream natural gas, renewable power generation, power transmission and opportunities in the international arena—that will extend our growth rate throughout the decade. O O P R R R R R A A C S U L E E E I T I I i i i i i r s s n h e r n n g e n e e e ry r a b b d d d W s s a a a t t l u E l l l w l i i l i i l i t m o o o e e e c n n b n s e e n n n e e e f r r r a a p d a a a a t t t t v l l x l y, y y m n o e e rf r p r a c . i i W i i r a s m n n e e o o o c u n g n e e e e e t r c p d a s c c s s t v t t l u u x u f l l w i f i i f t i i r r s c n n n o o o o r h e n v w g g n e t f r c a a d d a as s u l h i r a s d d d n n n h o o o h n e e e b e e e e e t r r r x d a a a s s t v f v l , y y i l l i s d m o o o o o o r e n v r s d p e e e r r d d u u c a a s . s t v u u t f i l d b l i l i i i s s n o o o o n e e e u t b n n c e g n e e r p b d s w w u t v u u l W y l t i r a m m n n e e e o o m s g d b p e e r r r r — a a a a p u a s s w t t w l f l , i i i i i i n o o o o o r h n n n n n e e p r p a m p g n e e e r rt a d u s s a s s t t t t w , i i i r r a n h e e o o o n n h n e g n e e t t r r r — a a a d a a w t t t t t u x l l w l o o e h u h d g d h e e t r ca . t t u

CORPORATE GOVERNANCE At Enbridge, corporate governance means that a comprehensive system of stewardship and accountability is in place and functioning among Directors, management and employees of the Company. Enbridge is committed to the principles of good governance, and the Company employs a variety of policies, programs and practices to manage corporate governance and ensure compliance. The Board of Directors is responsible for the overall stewardship of Enbridge and, in discharging that responsibility, reviews, approves and provides guidance with respect to the strategic plan and the operational risk management plan of the Company, and monitors their implementation. The Board approves all significant decisions that affect the Company, and reviews its financial and operational results. The Board also oversees identification of the Company’s principal risks on an annual basis, monitors risk management programs, reviews succession planning and compensation programs, and seeks assurance that internal control systems and management information systems are in place and operating effectively. BOARD OF DIRECTORS David A. Leslie Corporate Director, Toronto, Ontario Charles W. Fischer Corporate Director, Calgary, Alberta Charles E. Shultz Chair & Chief Executive Officer, Dauntless Energy Inc., Calgary, Alberta J. Herb England Chairman & Chief Executive Officer, Stahlman-England Irrigation Inc., Naples, Florida Catherine L. Williams Corporate Director, Calgary, Alberta George K. Petty Corporate Director, San Luis Obispo, California David A. Arledge Chair of the Board, Enbridge Inc., Naples, Florida J. Lorne Braithwaite President & Chief Executive Officer, Build Toronto, Thornhill, Ontario V. Maureen Kempston Darkes Corporate Director, Lauderdale-by-the-Sea, Florida Dan C. Tutcher Corporate Director, Houston, Texas James J. Blanchard Senior Partner, DLA Piper U.S., LLP, Beverly Hills, Michigan Al Monaco President & Chief Executive Officer, Enbridge Inc., Calgary, Alberta BOARD OF DIRECTORS (left to right) David A. Leslie, Charles W. Fischer, Charles E. Shultz, J. Herb England, Catherine L. Williams, George K. Petty, David A. Arledge, J. Lorne Braithwaite, V. Maureen Kempston Darkes, Dan C. Tutcher, James J. Blanchard, Al Monaco Corporate Governance > 27 O O D B D R R RE F A S O CT I C i D i i A h h s e e d e e r, r F a c a s . s . l l L v , l S r n e C h h n g erb J d u a s a E t l H . z . E l , , P i i i s m e o h r C e e g n e e r K W a at L t t . G l l . y, , i B D i i d or h dg n e e e e t r r A A a J a a t v w L . l . , , D re m n o t n e e p e e rk a a s s u K M , D B C s m h n n h e e t r r, a J d J Tu c c a a a l . . , A n o o c a M l

FORWARD-LOOKING INFORMATION Forward-looking information, or forwardlooking statements, have been included in this Annual Review to provide the Company’s shareholders and potential investors with information about the Company and its subsidiaries and affiliates, including management’s assessment of Enbridge’s and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate’’, ‘‘expect’’, ‘‘project’’, ‘‘estimate’’, ‘‘forecast’’, ‘‘plan’’, ‘‘intend’’, ‘‘target’’, ‘‘believe’’ and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to: expected earnings/ (loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows; expected costs related to projects under construction; expected in-service dates for projects under construction; expected capital expenditures; estimated future dividends; and expected costs related to leak remediation and potential insurance recoveries. Although Enbridge believes that these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about: the expected supply and demand for crude oil, natural gas, NGL and green energy; prices of crude oil, natural gas, NGL and green energy; expected exchange rates; inflation; interest rates; the availability and price of labour and pipeline construction materials; operational reliability; customer project approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service dates; and weather. Assumptions regarding the expected supply and demand of crude oil, natural gas, NGL and green energy; and the prices of these commodities, are material to and underlie all forward-looking statements. These factors are relevant to all forward-looking statements as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates, may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected earnings/ (loss) or adjusted earnings/(loss) and associated per share amounts, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on projects under construction, including estimated in-service date, and expected capital expenditures include: the availability and price of labour and pipeline construction materials; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; and the impact of weather and customer and regulatory approvals on construction schedules. Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to operating performance, regulatory parameters, project approval and support, weather, economic and competitive conditions, exchange rates, interest rates, commodity prices and supply and demand for commodities, including but not limited to those risks and uncertainties discussed in the Company’s annual review and in the Company’s other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Enbridge’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by law, Enbridge assumes no obligation to publicly update or revise any forward-looking statements made in this Annual Review or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements. NON-GAAP MEASURES This Annual Review contains references to adjusted earnings/(loss), which represent earnings or loss attributable to common shareholders adjusted for unusual, non-recurring or non-operating factors on both a consolidated and segmented basis. These factors, referred to as adjusting items, are reconciled and discussed in the Management’s Discussion and Analysis (MD&A) for the affected business segments. Management believes the presentation of adjusted earnings/(loss) provides useful information to investors and shareholders as it provides increased transparency and predictive value. Management uses adjusted earnings/ (loss) to set targets, assess performance of the Company and set the Company’s dividend payout target. Adjusted earnings/(loss) and adjusted earnings/(loss) for each of the segments are not measures that have a standardized meaning prescribed by U.S. GAAP and are not considered GAAP measures; therefore, these measures may not be comparable with similar measures presented by other issuers. See Non-GAAP Reconciliations in the MD&A, for a reconciliation of the GAAP and non-GAAP measures. 28 < ENBRIDGE INC. 2012 ANNUAL REVIEW

2012 AWARDS AND RECOGNITION By focusing on our core values of Integrity, Safety and Respect, Enbridge has received many awards and much recognition over the years for our performance in the areas of sustainability; environmental management; financial health; workplace health, safety and fairness; community relations; and public disclosure. Listed below are some of the awards and recognition we received in 2012. SUSTAINABILITY Global 100 Most Sustainable Corporations in the World The Global 100 Most Sustainable Corporations in the World, which is an annual assessment initiated by Corporate Knights magazine, highlights global corporations that have been most proactive in managing environmental, social and governance issues. Enbridge was named to the Global 100 in 2010, 2011, 2012 and again in January 2013. Dow Jones Sustainability Index (DJSI) Enbridge is included on both the World and North America index. The DJSI indices track the performance of large companies that lead the field in terms of sustainability, financial results, community relations and environmental stewardship. FTSE4Good Enbridge became a constituent of the 2012/2013 FTSE4Good Index Series. The Financial Times and the London Stock Exchange have designed this equity index series to objectively measure the performance of companies that meet globally recognized corporate responsibility standards with respect to environmental, social and governance matters. Carbon Disclosure Project (CDP) The CDP added Enbridge to its Carbon Disclosure Leadership Index, which highlights companies that have displayed a strong approach to information disclosure and management regarding GHG emissions. The CDP, which represents 722 institutional investors with $87 trillion in asset, is an independent not-for-profit organization working to drive GHG reduction and sustainable water use by business and cities. Best 50 Corporate Citizens in Canada Forbes 100 Most Trustworthy Companies in America Enbridge Energy Partners LP were listed as having the most transparent and conservative accounting practices and most prudent management. TOP EMPLOYER Canada’s Top 100 Employers Canada’s Top 100 Employers listing is a national evaluation to determine which employers lead their industries in offering exceptional workplaces for their employees. This is the eighth consecutive year Enbridge has been on the list, and eleventh since the list’s inception 13 years ago. Canada’s Greenest Employers Launched in 2007, this special designation recognizes the employers that lead the nation in creating a culture of environmental awareness in their organizations. Alberta’s Top Employers Alberta’s Top Employers is an annual competition organized by the editors of Canada’s Top 100 Employers in partnership with the Human Resources Institute of Alberta. The award recognizes the Alberta employers that lead their industries in offering exceptional places to work. ABORIGINAL RELATIONS Silver Level, Progressive Aboriginal Relations (PAR) Certification, Canadian Council for Aboriginal Business (CCAB) The CCAB is a national business organization whose members include Aboriginal businesses, Aboriginal community-owned economic development corporations, and companies operating in Canada. The CCAB’s PAR certification program recognizes and supports continuous improvement in Aboriginal relations. 2012 Awards and Recognition > 29 Corporate Knights magazine recognized Enbridge as being one of Canada’s Best 50 Corporate Citizens, the 10th year in a row the Company has been recognized. For the second year in a row, Enbridge was included on the highly prestigious top 10 list, earning eighth spot overall. The ranking is the longest running of its kind and is determined based on a thorough analysis of contenders’ environmental, social and governance indicators publicly disclosed.

ANNUAL MEETING The Annual Meeting of Shareholders will be held in the Ballroom at the Metropolitan Conference Centre, Calgary, Alberta at 1:30 p.m. MDT on Wednesday, May 8, 2013. A live audio webcast of the meeting will be available at enbridge.com and will be archived on the site for approximately one year. Webcast details will be available on the Company’s website closer to the meeting date. Le présent document est disponible en français. REGISTRAR AND TRANSFER AGENT IN CANADA For information relating to shareholdings, shareholder investment plan, dividends, direct dividend deposit, dividend re-investment accounts and lost certificates please contact: CIBC Mellon Trust Company 1 P.O. Box 700 Station B Montreal, Québec, Canada H3B 3K3 Toll free: 800.387.0825 Internet: canstockta.com/investorinquiry CIBC Mellon Trust Company also has offices in Halifax, Toronto, Calgary and Vancouver. 1 Canadian Stock Transfer Company Inc. acts as the Administrative Agent for CIBC Mellon Trust Company CO-REGISTRAR AND CO-TRANSFER AGENT IN THE UNITED STATES Computershare 480 Washington Blvd. Jersey City, New Jersey U.S.A. 07310 COMMON AND PREFERENCE SHARES The Common Shares of Enbridge Inc. trade in Canada on the Toronto Stock Exchange and in the United States on the New York Stock Exchange under the trading symbol ‘‘ENB.’’ The Preference Shares of Enbridge Inc. trade in Canada on the Toronto Stock Exchange under the trading symbols: Series A – ENB.PR.A Series B – ENB.PR.B Series D – ENB.PR.D Series F – ENB.PR.F Series H – ENB.PR.H Series J – ENB.PR.U Series L – ENB.PF.U Series N – ENB.PR.N Series P – ENB.PR.P Series R – ENB.PR.T 2013 ENBRIDGE INC. COMMON SHARE DIVIDENDS Q1 Q2 Q3 Dividend $0.315 $ – 4 $ – Payment date Mar. 1 Jun. 1 Sep. 1 Record date 1 Feb. 15 May 15 Aug. 15 SPP deadline 2 Feb. 22 May 27 Aug. 24 DRIP enrollment 3 Feb. 8 May 8 Aug. 8 1 Dividend record dates for Common Shares are generally February 15, May 15, August 15 and November 15 in each year unless the 15th falls on a Saturday or Sunday. 2 The Share Purchase Plan cut-off date is five business days prior to the dividend payment date. 3 The Dividend Reinvestment Program enrollment cut-off date is five business days prior to the dividend record date. 4 Amount will be announced as declared by the Board of Directors. SHAREHOLDER INQUIRIES If you have inquiries regarding the following: Dividend Reinvestment and Share Purchase Plan; Change of address; Share transfer; Lost certificates; Dividends; or Duplicate mailings please contact the registrar and transfer agent—CIBC Mellon Trust Company. OTHER INVESTOR INQUIRIES If you have inquiries regarding the following: Additional financial or statistical information; Industry and company developments; Latest news releases or investor presentations; or Any other investment-related inquiries please contact Enbridge Investor Relations or visit Enbridge’s website at enbridge.com CORPORATE SOCIAL RESPONSIBILITY REPORT Enbridge publishes an annual Corporate Social Responsibility report. The report is available on the Company’s website at csr.enbridge.com 30 < ENBRIDGE INC. 2012 ANNUAL REVIEW Q4 $ – Dec. 1 Nov. 15 Nov. 25 Nov. 8 4 4

Designed and produced by Karo Group. Printed in British Columbia, Canada by Blanchette Press. Enbridge Inc., a Canadian company, is a North American leader in delivering energy and one of the Global 100 Most Sustainable Corporations in the World. As a transporter of energy, Enbridge operates in Canada and the U.S., the world’s longest crude oil and liquids transportation system. The Company also has a significant and growing involvement in natural gas gathering, transmission and midstream businesses, and an increasing involvement in power transmission. As a distributor of energy, Enbridge owns and operates Canada’s largest natural gas distribution company, and provides distribution services in Ontario, Quebec, New Brunswick and New York State. As a generator of energy, Enbridge has interests in close to 1,300 megawatts of renewable and alternative energy generating capacity and is expanding its interests in wind and solar energy and geothermal. Enbridge employs approximately 10,000 people, primarily in Canada and the U.S. and is ranked as one of Canada’s Greenest Employers and one of the Top 100 Companies to Work for in Canada. Enbridge’s common shares trade on the Toronto and New York stock exchanges under the symbol ENB. For more information, visit enbridge.com Enbridge is committed to reducing its impact on the environment in every way, including the production of this publication. This report was printed entirely on FSC® Certified paper, which is manufactured entirely with wind energy and contains 100% post-consumer recycled fibre.

3000, 425 – 1st Street S.W. Calgary, Alberta, Canada T2P 3L8 Telephone: 403.231.3900 Facsimile: 403.231.3920 Toll free: 800.481.2804 enbridge.com

Our investors have come to expect superior returns,and that’s what we’re delivering. ENBRIDGE INC. FINANCIAL REPORT 2012 N I IN . E E R D B

Forward-Looking Information: This Financial Report includes references to forward-looking information. By its nature this information applies certain assumptions and expectations about future outcomes, so we remind you it is subject to risks and uncertainties that affect every business, including ours. The more significant factors and risks that might affect future outcomes for Enbridge are listed and discussed in the “Forward- Looking Information” section on page 8 of this Financial Report and also in the risk sections of our public disclosure filings, including Management’s Discussion and Analysis, available on both the SEDAR and EDGAR systems at www.sedar.com and www.sec.gov/edgar.shtml.

MANAGEMENT’S DISCUSSION AND ANALYSIS 2 Overview 4 Performance Overview 9 Corporate Vision, Strategy and Values 13 Industry Fundamentals 16 Growth Projects – Commercially Secured Projects 18 Liquids Pipelines 23 Gas Distribution 24 Gas Pipelines, Processing and Energy Services 27 Sponsored Investments 32 Corporate 32 Growth Projects – Other Projects Under Development 35 Liquids Pipelines 45 Gas Distribution 50 Gas Pipelines, Processing and Energy Services 59 Sponsored Investments 70 Corporate 72 Liquidity and Capital Resources 77 Commitments and Contingencies 79 Quarterly Financial Information 80 Related Party Transactions 80 Risk Management and Financial Instruments 87 Critical Accounting Estimates 89 Changes in Accounting Policies 91 Controls and Procedures 92 Non-GAAP Reconciliations CONSOLIDATED FINANCIAL STATEMENTS 93 Management’s Report 94 Independent Auditor’s Report 96 Consolidated Statements of Earnings 97 Consolidated Statements of Comprehensive Income 98 Consolidated Statements of Changes in Equity 99 Consolidated Statements of Cash Flows 100 Consolidated Statements of Financial Position NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 156 Five-Year Consolidated Highlights 158 Glossary 159 Investor Information 101 1. General Business Description 102 2. Summary of Significant Accounting Policies 110 3. Changes in Accounting Policies 111 4. Segmented Information 113 5. Financial Statement Effects of Rate Regulation 115 6. Acquisitions 117 7. Accounts Receivable and Other 117 8. Inventory 118 9. Property, Plant and Equipment 119 10. Variable Interest Entity 120 11. Long-Term Investments 122 12. Deferred Amounts and Other Assets 122 13. Intangible Assets 123 14. Goodwill 123 15. Accounts Payable and Other 124 16. Debt 125 17. Other Long-Term Liabilities 126 18. Noncontrolling Interests 127 19. Share Capital 129 20. Stock Option and Stock Unit Plans 132 21. Components of Accumulated Other Comprehensive Loss 133 22. Derivative Financial Instruments and Hedging Activities 143 23. Income Taxes 146 24. Retirement and Postretirement Benefits 151 25. Other Income 151 26. Changes in Operating Assets and Liabilities 151 27. Related Party Transactions 152 28. Commitments and Contingencies 155 29. Guarantees > 1 2012 FINANCIAL REPORT

MANAGEMENT’S DISCUSSION AND ANALYSIS This Management’s Discussion and Analysis (MD&A) dated February 14, 2013 should be read in conjunction with the audited consolidated financial statements and notes thereto of Enbridge Inc. (Enbridge or the Company) for the year ended December 31, 2012, prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP). Where applicable, comparative figures presented within this MD&A have been restated to correspond to the Company’s consolidated financial statements prepared in accordance with U.S. GAAP for the years ended December 31, 2011 and 2010. All financial measures presented in this MD&A are expressed in Canadian dollars, unless otherwise indicated. Additional information related to the Company, including its Annual Information Form, is available on SEDAR at www.sedar.com. Overview Enbridge is a North American leader in delivering energy. As a transporter of energy, Enbridge operates, in Canada and the United States, the world’s longest crude oil and liquids transportation system. The Company also has significant and growing involvement in natural gas gathering, transmission and midstream businesses and an increasing involvement in power transmission. As a distributor of energy, Enbridge owns and operates Canada’s largest natural gas distribution company and provides distribution services in Ontario, Quebec, New Brunswick and New York State. As a generator of energy, Enbridge has interests in close to 1,300 megawatts (MW) of renewable and alternative energy generating capacity and is expanding its interests in wind, solar and geothermal. Enbridge has approximately 10,000 employees and contractors, primarily in Canada and the United States. The Company’s activities are carried out through five business segments: Liquids Pipelines; Gas Distribution; Gas Pipelines, Processing and Energy Services; Sponsored Investments; and Corporate, as discussed below. LIQUIDS PIPELINES Liquids Pipelines consists of common carrier and contract crude oil, natural gas liquids (NGL) and refined products pipelines and terminals in Canada and the United States, including Canadian Mainline, Regional Oil Sands System, Southern Lights Pipeline, Seaway Pipeline, Spearhead Pipeline and Feeder Pipelines and Other. TOTAL ASSETS (millions of Canadian dollars) 1 Financial information has been extracted from financial statements prepared in accordance with U.S. GAAP. 2 Financial information has been extracted from financial statements prepared in accordance with Canadian GAAP. 19,907 2 24,701 2 36,552 1 41,494 1 47,172 1 12 11 10 09 08 Liquids Pipelines Gas Distribution Gas Pipelines, Processing and Energy Services Sponsored Investments Corporate 2 < ENBRIDGE INC. 2012 FINANCIAL REPORT S C O D D S S A A ’ LY A A A N U G S S S N N T N E M E N M I I I

Management’s Discussion and Analysis > 3 GAS DISTRIBUTION Gas Distribution consists of the Company’s natural gas utility operations, the core of which is Enbridge Gas Distribution Inc. (EGD), which serves residential, commercial and industrial customers, primarily in central and eastern Ontario as well as northern New York State. This business segment also includes natural gas distribution activities in Quebec and New Brunswick. GAS PIPELINES, PROCESSING AND ENERGY SERVICES Gas Pipelines, Processing and Energy Services consists of investments in natural gas pipelines and processing and gathering facilities and the Company’s energy services businesses, along with renewable energy projects. Investments in natural gas pipelines include the Company’s interests in the United States portion of the Alliance System (Alliance Pipeline US), the Vector Pipeline (Vector) and transmission and gathering pipelines in the Gulf of Mexico. Investments in natural gas processing include the Company’s interest in Aux Sable, a natural gas fractionation and extraction business located at the terminus of the Alliance System (Alliance). The energy services businesses undertake physical commodity marketing activity and manage the Company’s volume commitments on the Alliance, Vector and other pipeline systems. SPONSORED INVESTMENTS Sponsored Investments includes the Company’s 21.8% ownership interest in Enbridge Energy Partners, L.P. (EEP), Enbridge’s 66.7% investment in the United States segment of the Alberta Clipper Project through EEP and Enbridge Energy, Limited Partnership (EELP) and an overall 67.7% economic interest in Enbridge Income Fund (the Fund), held both directly and indirectly through Enbridge Income Fund Holdings Inc. (ENF). Enbridge manages the day-to-day operations of, and develops and assesses opportunities for each of these investments, including both organic growth and acquisition opportunities. EEP transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines and transports, gathers, processes and markets natural gas and NGL. The primary operations of the Fund include renewable power generation projects, crude oil and liquids pipeline and storage businesses in Western Canada and a 50% interest in the Canadian portion of the Alliance System (Alliance Pipeline Canada). CORPORATE Corporate consists of the Company’s investment in Noverco Inc. (Noverco), new business development activities, general corporate investments and financing costs not allocated to the business segments.

Performance Overview Three Months Ended December 31, Year Ended December 31, 2012 2011 2012 2011 2010 (millions of Canadian dollars, except per share amounts) Earnings attributable to common shareholders Liquids Pipelines 136 203 726 505 531 Gas Distribution 127 (226) 207 (88) 150 Gas Pipelines, Processing and Energy Services (52) 156 (478) 305 125 Sponsored Investments 71 89 282 269 98 Corporate (136) (63) (127) (171) 40 146 159 610 820 944 Earnings per common share 1 0.19 0.21 0.79 1.09 1.27 Diluted earnings per common share 1 0.18 0.21 0.78 1.08 1.26 Adjusted earnings 2 Liquids Pipelines 183 126 684 536 511 Gas Distribution 63 48 176 173 162 Gas Pipelines, Processing and Energy Services 37 41 154 163 123 Sponsored Investments 67 74 263 244 206 Corporate (23) (16) (28) (16) (25) 327 273 1,249 1,100 977 Adjusted earnings per common share 1,2 0.42 0.36 1.62 1.46 1.32 Cash flow data Cash provided by operating activities 502 823 2,874 3,371 1,877 Cash used in investing activities (2,182) (2,676) (6,204) (5,079) (3,902) Cash provided by financing activities 1,725 1,435 4,395 2,030 1,957 Dividends Common share dividends declared 227 190 895 759 648 Dividends paid per common share 1 0.2825 0.2450 1.13 0.98 0.85 Revenues Commodity sales 5,111 5,195 19,101 20,611 15,863 Gas distribution sales 585 568 1,910 1,906 1,814 Transportation and other services 1,477 1,546 4,295 4,536 3,843 7,173 7,309 25,306 27,053 21,520 Total assets 47,172 41,949 47,172 41,949 36,423 Total long-term liabilities 25,345 24,074 25,345 24,074 22,171 1 Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011. 2 Adjusted earnings and adjusted earnings per common share are non-GAAP measures that do not have any standardized meaning prescribed by generally accepted accounting principles. For more information on non-GAAP measures see page 9. 4 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 5 EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS Earnings attributable to common shareholders were $610 million ($0.79 per common share) for the year ended December 31, 2012 compared with $820 million ($1.09 per common share) for the year ended December 31, 2011 and $944 million ($1.27 per common share) for the year ended December 31, 2010. The Company has delivered significant earnings growth from operations over the course of the last three years, as discussed below in Performance Overview – Adjusted Earnings; however, the positive impact of this growth was reduced by a number of unusual, non-recurring or non-operating factors, the most significant of which are changes in unrealized derivative fair value and foreign exchange gains or losses. The Company has a comprehensive long-term economic hedging program to mitigate exposures to interest rate, foreign exchange and commodity price exposures. The changes in unrealized mark-to-market accounting impacts from this program create volatility in short-term earnings but the Company believes over the long-term it supports reliable cash flows and dividend growth. Earnings for 2012 and 2011 were also negatively impacted by the transfer of assets between entities under common control of Enbridge. Intercompany gains realized as a result of these asset transfers for both years have been eliminated for accounting purposes; however, income taxes of $56 million and $98 million for the years ended December 31, 2012 and 2011, respectively, incurred on the related capital gains remain as charges to consolidated earnings. Other significant items impacting the comparability of earnings year-over-year were costs and related insurance recoveries associated with the Lines 6A, 6B and Line 14 crude oil releases. Earnings for the years ended December 31, 2012, 2011 and 2010 included the Company’s after-tax share of EEP’s costs, before insurance recoveries and excluding fines and penalties, of $9 million, $33 million and $103 million, respectively, related to these incidents. Insurance recoveries recorded for the years ended December 31, 2012 and 2011 were $24 million and $50 million after-tax attributable to Enbridge, respectively, related to the Line 6B crude oil release. See Sponsored Investments – Enbridge Energy Partners L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases. Fourth quarter earnings drivers were largely consistent with year-to-date trends and continued to include changes in unrealized fair value derivative and foreign exchange gains and losses. Aside from operating factors discussed in Performance Overview – Adjusted Earnings, factors unique to the fourth quarter of 2012 included a $105 million asset impairment to Stingray and Garden Banks assets within Enbridge Offshore Pipelines (Offshore), $56 million of income taxes on the intercompany gain on sale to the Fund not eliminated for accounting purposes and a $63 million gain on recognition of a regulatory asset related to other postretirement benefits (OPEB) within EGD. Earnings for the comparable fourth quarter of 2011 reflected the discontinuance of rate-regulated accounting at Enbridge Gas New Brunswick Inc. (EGNB), which resulted in a write-off of a deferred regulatory asset and certain capitalized operating costs, totaling $262 million, net of tax. See Gas Distribution – Other Gas Distribution and Storage – Enbridge Gas New Brunswick Inc. – Regulatory Matters. EARNINGS APPLICABLE TO COMMON SHAREHOLDERS (millions of Canadian dollars) 1 Financial information has been extracted from financial statements prepared in accordance with U.S. GAAP. 2 Financial information has been extracted from financial statements prepared in accordance with Canadian GAAP. 667 2 645 2 556 2 615 2 700 2 1,321 2 1,555 2 944 1 820 1 610 1 12 11 10 09 08 07 06 05 04 03

ADJUSTED EARNINGS A key tenet of the Company’s investor value proposition is “visible growth”, supported by an ongoing focus on safe and reliable operations and a disciplined approach to investment and project execution. The Company has consistently delivered on this proposition, growing adjusted earnings from $1.32 per common share in 2010 to $1.46 per common share in 2011 and $1.62 per common share in 2012. The upward trend in adjusted earnings over these years was predominantly attributable to strong operating performance from the Company’s Liquids Pipelines assets as well as contributions from new assets placed into service. Incremental oil sands production in Alberta and strong production growth out of the Bakken in North Dakota has increased volumes transported on the Canadian Mainline system and the Lakehead System owned by EEP. The increase in volumes most notably impacted adjusted earnings from mid-2011 onward when the Competitive Toll Settlement (CTS) on the Canadian Mainline took effect. Under the CTS, Canadian Mainline earnings are exposed to volume and cost variability. In 2012, the Company also began realizing earnings from its 50% interest in the Seaway Crude Pipeline System (Seaway Pipeline). The Seaway Pipeline, which commenced southbound service from the United States midwest to the Gulf Coast in May 2012, has experienced strong volumes since inception as shippers have sought to transport their product to locations where realized prices are more favourable. Similarly, adjusted earnings growth on the Spearhead Pipeline increased in 2012 as it also benefited from producers’ desire to move crude onward to Gulf Coast markets in order to capture attractive price differentials. In addition to the Seaway Pipeline, other new assets commencing operations and contributing to adjusted earnings growth included the Cedar Point Wind Energy Project (Cedar Point) in late 2011 and the Silver State North Solar Project (Silver State) in 2012. The Company has also seen a marked increase in operating costs over this time frame. Under the umbrella of its Operational Risk Management Plan (ORM Plan) launched in 2011, the Company has bolstered spending in the areas of system integrity, environmental and safety programs to ensure the safe and reliable operations of all of its assets. Other factors which contributed to changes in adjusted earnings year-over-year included market factors impacting the Company’s Energy Services and natural gas businesses, as well as increased preference share dividends due to the Company’s increased activity in the capital markets to prefund future growth projects. Energy Services experienced strong adjusted earnings growth from 2010 to 2011 but saw this growth temper somewhat in 2012 as changing market conditions gave rise to fewer margin opportunities in crude oil and NGL marketing. Within Sponsored Investments, EEP’s natural gas business reflected a similar trend with growth in adjusted earnings in 2011 over 2010 owing to higher natural gas volumes and contributions from acquired assets, followed by a decline in 2012 due to persistent weakness in natural gas commodity prices. Aux Sable contributed to growth over both the 2011 and 2012 time periods as new assets were placed into service and realized fractionation margins remained high. With respect to the fourth quarter of 2012, many of these same annual trends continued. The primary drivers of adjusted earnings growth period-over-period included strong volumes on the Company’s liquids pipelines assets both in Canada and the United States, including contributions from new assets such as the Seaway Pipeline, customer expansion at EGD and growth in the Company’s renewable energy portfolio. Contributions from the Gas Pipelines, Processing and Energy Services segment were relatively flat as higher adjusted earnings from Aux Sable were offset by fewer margin opportunities in liquids marketing and increased costs within Offshore. ADJUSTED EARNINGS (millions of Canadian dollars) 1 Financial information has been extracted from financial statements prepared in accordance with U.S. GAAP. 2 Financial information has been extracted from financial statements prepared in accordance with Canadian GAAP. 496 2 491 2 537 2 593 2 637 2 677 2 855 2 977 1 1,100 1 1,249 1 12 11 10 09 08 07 06 05 04 03 6 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 7 CASH FLOWS Cash provided by operating activities was $2,874 million for the year ended December 31, 2012, mainly driven by strong operating performance from the Company’s core assets, particularly from Liquids Pipelines and the cash flow generation from growth projects placed into service in recent years. Offsetting this cash inflow were changes in operating assets and liabilities which fluctuate in the normal course due to various factors impacting the timing of cash receipts and payments. In 2012, the Company was active in the capital markets with the issuance of $2,634 million in preference shares, common shares of approximately $384 million and $2,199 million in medium-term notes and also significantly bolstered its liquidity through the securement of additional credit facilities. The proceeds of the capital market transactions, together with cash from operations, were more than sufficient to finance the Company’s $6.2 billion net investment in expansion initiatives during 2012 and provides financing flexibility for the Company’s growth opportunities in 2013. DIVIDENDS The Company has paid common share dividends since its inception in 1953. In December 2012, the Company announced a 12% increase in its quarterly dividend to $0.315 per common share, or $1.26 annualized effective March 1, 2013. Assuming this currently announced quarterly dividend is annualized for 2013, the Company has generated compound annual average growth of 11.7% since 2003. The Company continues to target a dividend payout of approximately 60% to 70% of adjusted earnings over the longer term. In 2012, the dividend payout was 70% (2011 – 67%; 2010 – 64%) of adjusted earnings per share. REVENUES The Company generates revenue from three primary sources: commodity sales, gas distribution sales and transportation and other services. Commodity sales of $19,101 million for the year ended December 31, 2012 (2011 – $20,611 million; 2010 – $15,863 million) were earned through the Company’s energy services operations. Revenues from these operations depends on activity levels, which vary from year to year depending on market conditions and commodity prices. Commodity prices do not directly impact earnings since such earnings reflect a margin or percentage of revenue which depends more on differences in commodity prices between locations and points in time than on the absolute level of prices. Gas distribution sales are primarily earned by EGD and are recognized in a manner consistent with the underlying rate-setting mechanism mandated by the regulator. Revenues generated by the gas distribution businesses are driven by volumes delivered, which vary with weather and customer base, as well as regulator-approved rates. The cost of natural gas is charged to customers through rates but does not ultimately impact earnings due to the pass through nature of these costs. DIVIDENDS PER COMMON SHARE (millions of Canadian dollars) 0.41 0.46 0.52 0.57 0.62 0.66 0.74 0.85 0.98 1.13 1.26 13e 12 11 10 09 08 07 06 05 04 03

Transportation and other services revenues are earned from the Company’s crude oil and natural gas pipeline transportation businesses and also includes power production revenue from the Company’s portfolio of renewable power generation assets. For the Company’s transportation assets operating under market-based arrangements, revenues are driven by volumes transported and tolls. For rate-regulated assets, revenues are charged in accordance with tolls established by the regulator and, in most cost-of-service based arrangements, is reflective of the Company’s cost to provide the service plus a regulator-approved rate of return. FORWARD-LOOKING INFORMATION Forward-looking information, or forward-looking statements, have been included in this MD&A to provide the Company’s shareholders and potential investors with information about the Company and its subsidiaries and affiliates, including management’s assessment of Enbridge’s and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate’’, ‘‘expect’’, ‘‘project’’, ‘‘estimate’’, ‘‘forecast’’, ‘‘plan’’, ‘‘intend’’, ‘‘target’’, ‘‘believe’’ and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to: expected earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows; expected costs related to projects under construction; expected in-service dates for projects under construction; expected capital expenditures; estimated future dividends; and expected costs related to leak remediation and potential insurance recoveries. Although Enbridge believes these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about: the expected supply and demand for crude oil, natural gas, NGL and green energy; prices of crude oil, natural gas, NGL and green energy; expected exchange rates; inflation; interest rates; the availability and price of labour and pipeline construction materials; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service dates; and weather. Assumptions regarding the expected supply and demand of crude oil, natural gas, NGL and green energy, and the prices of these commodities, are material to and underlie all forward-looking statements. These factors are relevant to all forward-looking statements as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates, may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected earnings/(loss) or adjusted earnings/(loss) and associated per share amounts, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on projects under construction, including estimated in-service date and expected capital expenditures include: the availability and price of labour and construction materials; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; and the impact of weather and customer and regulatory approvals on construction schedules. Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to operating performance, regulatory parameters, project approval and support, weather, economic and competitive conditions, exchange rates, interest rates, commodity prices and supply and demand for commodities, including but not limited to those risks and uncertainties discussed in this MD&A and in the Company’s other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Enbridge’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by law, Enbridge assumes no obligation to publicly update or revise any forward-looking statements made in this MD&A or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements. 8 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 9 NON-GAAP MEASURES This MD&A contains references to adjusted earnings/(loss), which represent earnings or loss attributable to common shareholders adjusted for unusual, non-recurring or non-operating factors on both a consolidated and segmented basis. These factors, referred to as adjusting items, are reconciled and discussed in the financial results sections for the affected business segments. Management believes the presentation of adjusted earnings/(loss) provides useful information to investors and shareholders as it provides increased transparency and predictive value. Management uses adjusted earnings/(loss) to set targets, assess performance of the Company and set the Company’s dividend payout target. Adjusted earnings/(loss) and adjusted earnings/(loss) for each of the segments are not measures that have a standardized meaning prescribed by U.S. GAAP and are not considered GAAP measures; therefore, these measures may not be comparable with similar measures presented by other issuers. See Non-GAAP Reconciliations for a reconciliation of the GAAP and non-GAAP measures. Corporate Vision, Strategy and Values VISION Enbridge’s vision is to be the leading energy delivery company in North America. The Company transports, distributes and generates energy and its primary purpose is to deliver the energy North Americans need in the safest, most reliable and most efficient way possible. Among its peers, Enbridge strives to be the leader, which means not only leadership in value creation for shareholders but also leadership with respect to safety, operational reliability, environmental stewardship, customer service, employee satisfaction and community investment. Value for shareholders is evident in the Company’s proven investment value proposition which combines visible growth, a reliable business model and a growing income stream. STRATEGY The Company’s initiatives center around six areas of strategic emphasis. These strategies are reviewed at least annually with direction from its Board of Directors. 1. Commitment to Operational Safety and Reliability, and Environmental Protection; 2. Focus on Project Execution; 3. Attracting, Retaining and Developing Highly Capable People; 4. Preserving Financial Strength and Flexibility; 5. Strengthening Core Businesses; and 6. Developing New Platforms for Growth and Diversification. COMMITMENT TO OPERATIONAL SAFETY AND RELIABILITY, AND ENVIRONMENTAL PROTECTION Operations safety and system integrity continues to be Enbridge’s number one priority and sets the foundation for the strategic plan. An important element of this priority is the ORM Plan which broadly aims to position Enbridge as the industry leader for system integrity, environmental and safety programs, and charts the course for best-in-class practices. Through the ORM Plan, the Company has enhanced its integrity management, leak detection and control systems. The ORM Plan has also bolstered incident response capabilities, employee and public safety, and improved communication with landowners and first responders. Further, in an ongoing commitment to foster a positive pervasive safety culture, Life Saving Rules were rolled out in early 2012 to all employees which support the goal of ensuring every employee returns home safely at the end of the day and that the Company’s customers and communities in which it operates are kept safe.

FOCUS ON PROJECT EXECUTION Timely and cost-effective execution of the existing slate of $27 billion in commercially secured projects continues to be a key priority for the Company. Enbridge believes project execution is a core competency and the Company continues to build upon its rigorous project management processes, primarily through the Major Projects group. The key strategy for Major Projects of delivering projects safely, on time and on budget is supported by repeatable and competitive proposal development; long-term supply chain agreements; quality design, materials and construction; extensive public consultation; robust cost, schedule and risk controls; developed project management expertise; and efficient project transition to operating units. ATTRACTING, RETAINING AND DEVELOPING HIGHLY CAPABLE PEOPLE Investing in the attraction, retention and development of employees and future leaders is fundamental to executing Enbridge’s aggressive growth strategy and creating sustainability for future success. People-related focus areas include broadening recruiting efforts beyond traditional industry and geographical reaches, ensuring succession capability through accelerated leadership development programs and building change management capabilities throughout the enterprise to ensure projects and initiatives achieve the intended benefits. Furthermore, Enbridge strives to maintain industry competitive compensation and retention programs that provide both short-term and long-term incentives. PRESERVING FINANCIAL STRENGTH AND FLEXIBILITY The maintenance of adequate financial strength and flexibility is crucial to Enbridge’s growth strategy. Enbridge’s financial strategies are designed to ensure the Company has sufficient financial flexibility to meet its capital requirements. To support this objective, the Company develops financing plans and strategies to maintain or improve its credit ratings, diversify its funding sources and maintain substantial standby bank credit capacity and access to capital markets in both Canada and the United States. A key tenet of the Company’s reliable business model is mitigation of exposure to market price risks. The Company has robust risk management processes which ensure earnings volatility from market price risk is managed within the parameters of its earnings-at-risk policy. Enbridge will continue to proactively hedge interest rate, foreign exchange and commodity price exposures. Management of counterparty credit risk also remains an ongoing priority. The Company continually assesses ways to generate value for shareholders, including reviewing opportunities that may lead to acquisitions, dispositions or other strategic transactions, some of which may be material. Opportunities are screened, analyzed and must meet operating, strategic and financial benchmarks before being pursued. STRENGTHENING CORE BUSINESSES The Company has an established history of delivering on its value proposition through its Liquids Pipelines and gas transportation businesses which serve the transportation needs of key North American crude oil and natural gas markets. Shifting supply and demand fundamentals and North American price dislocations are driving significant infrastructure investment opportunities that Enbridge is well suited to capture in these core business segments. Within the Liquids Pipelines segment, strategies are focused on expanding access to new markets in North America for growing production from western Canada and the Bakken, expanding the capacity of the mainline pipeline system and strengthening the Company’s position in the Alberta oil sands and Bakken regions to ensure growing production volumes ultimately flow on Enbridge’s downstream systems. 10 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 11 Through Enbridge’s new market access initiatives, shippers will be provided greater connectivity to markets in Ontario, Quebec, the Gulf Coast and upper-midwest, with the objective of being able to secure the best pricing for their products. Significant market access programs announced in 2012 included the Gulf Coast Access, Eastern Access and Light Oil Market Access programs. To facilitate these downstream growth projects and continued growth in base volumes, a number of supporting mainline expansions are being undertaken. The Company’s efforts to expand market access and provide better netbacks for producers include further initiatives to access the Canadian and United States east coast and eastern Gulf Coast markets, as well as development of the proposed Northern Gateway Project (Northern Gateway), which would provide access to markets off the Pacific coast of Canada. Regional liquids pipeline development involves projects which connect new oil sands production to existing hubs on the Canadian Mainline. Enbridge, the largest pipeline operator in the oil sands region of Alberta, is currently developing close to $3.5 billion of commercially secured regional oil sands transportation facilities that are expected to be placed into service between 2012 and 2015, including the twinning and expansion of its Athabasca Pipeline and the expansion of its Waupisoo Pipeline. The Company also has $3.2 billion of secured system expansion projects in Saskatchewan and North Dakota, where Enbridge believes it is strategically located to capture increased production from the Bakken play. The fundamentals of the natural gas market in North America have been altered significantly in recent years with the emergence of unconventional shale gas plays. The Company’s natural gas strategies include leveraging competitive advantages of its existing assets and expanding its footprint in these emerging areas. Alliance is well positioned to service developing regions in northeast British Columbia and the Bakken play, and is evaluating opportunities to expand its service offerings in those areas as well as strategies to attract liquids rich gas onto the system. Development of shale plays is also creating the need for additional Canadian midstream infrastructure; an opportunity which fits with the Company’s investment value proposition and which can leverage existing operational expertise. The Company’s first operations within this space are expected to commence with the completion of its Peace River Arch (PRA) Gas Development in 2013. Within the United States gas business, strategic priorities include expanding gathering and processing capacity, particularly in the Granite Wash area, and seeking opportunities to expand its service offerings, including NGL transportation. In addition to these onshore strategies, the Company continues to pursue crude oil and natural gas gathering expansion opportunities for ultra-deep projects in the Gulf of Mexico. DEVELOPING NEW PLATFORMS FOR GROWTH AND DIVERSIFICATION The development of new platforms to diversify and sustain long-term growth is an important strategy for Enbridge. The Company is currently focusing its development efforts towards securing investment opportunities in renewable and gas-fired power generation, power transmission and select international assets. The Company also invests in early stage energy technologies that complement the Company’s core businesses. Enbridge has advanced its renewable power strategy considerably over the last several years and has interests in a renewable energy portfolio with a generation capacity of more than 1,300 MW. Future investment may include earlier stage development opportunities, including expansion of existing sites. The Company is also assessing opportunities to invest in gas-fired generation, which is projected to grow significantly over the long-term based on natural gas supply fundamentals and the long-term natural gas price outlook. Power transmission is also an attractive growth opportunity and a complement to the Company’s electricity generation platform. There is substantial need for new transmission infrastructure in North America, with risk and return profiles that fit Enbridge’s investment value proposition. The Company is targeting completion of construction of the initial phase of its first transmission project, the Montana-Alberta Tie-Line (MATL), by the middle of 2013.

CORPORATE VALUES Enbridge adheres to a strong set of core values that govern how it conducts its business and pursues strategic priorities. In light of the significant growth in employees in recent years and projected future growth, the Company recently refreshed and re-emphasized these values, articulated as: “Enbridge employees demonstrate integrity, safety and respect in support of our communities, the environment and each other”. Employees are required to uphold these values in their interactions with each other, with customers, suppliers, landowners, community members and all others with whom the Company deals, and to ensure the Company’s business decisions are consistent with these values. MAINTAINING THE COMPANY’S SOCIAL LICENSE Earning and maintaining “social license”—the approval and acceptance of the communities in which the Company is proposing projects—is critical to Enbridge’s ability to execute on its growth plans. To earn the public’s trust, and to protect and reinforce the Company’s reputation with its stakeholders, Enbridge is committed to integrating Corporate Social Responsibility (CSR) into every aspect of its business. The Company defines CSR as conducting business in an ethical and responsible manner, protecting the environment and the safety of people, providing economic and other benefits to the communities in which the Company operates, supporting universal human rights and employing a variety of policies, programs and practices to manage corporate governance and ensure fair, full and timely disclosure. The Company provides its stakeholders with open, transparent disclosure of its CSR performance and prepares its annual CSR Report using the Global Reporting Initiative sustainability reporting guidelines, which serve as a generally accepted framework for reporting on an organization’s economic, environmental and social performance. The 2012 CSR Report can be found at csr.enbridge.com. None of the information contained on, or connected to, the Enbridge website is incorporated or otherwise part of this MD&A. One of Enbridge‘s CSR environmental objectives is its Neutral Footprint plan, which includes initiatives to counteract the environmental impact of all Enbridge’s pipeline expansion projects within five years of their occurrence. Neutral Footprint initiatives include: planting a tree for every tree the Company removes to build new facilities; conserving an acre of land for every acre of wilderness the Company permanently impacts; and generating a kilowatt of renewable energy for every kilowatt the Company’s expansions consume. Progress updates on the Company’s Neutral Footprint initiatives can be found at enbridge.com/neutralfootprint and in the annual CSR Report. None of the information contained on, or connected to, the Enbridge website is incorporated or otherwise part of this MD&A. To complement community investments in its Canadian and United States operating areas, Enbridge created the energy4everyone foundation (the Foundation) in 2009. The Foundation aims to leverage the expertise and resources of the Canadian energy industry to affect significant positive change through the delivery and deployment of affordable, reliable and sustainable energy services and technologies in communities in need around the world. To date, the Foundation has completed projects in Costa Rica, Ghana, Nicaragua, Peru and Tanzania. 12 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 13 Industry Fundamentals SUPPLY AND DEMAND FOR LIQUIDS Enbridge has an established and successful history of being the largest transporter of crude oil to the United States, the world’s largest market. While United States demand for Canadian crude oil production will support the use of Enbridge infrastructure for the foreseeable future, North American and global crude oil supply and demand fundamentals are shifting and Enbridge has a crucial role to play in this transition by developing long-term transportation options that enable the efficient flow of crude oil from supply regions to end-use markets. Overall, global energy consumption is expected to continue to grow; however, growth in crude oil demand is expected to be increasingly driven by emerging markets, such as China, India and the Middle East. In Organisation for Economic Co-operation and Development countries, including Canada, the United States and western Europe, conservation, stagnant population growth and a shift to alternative energy will reduce crude oil demand over the long term. Accordingly, there is a strategic opportunity for North American producers to meet growing global demand outside North America. Access to new markets is expected to improve netbacks for domestic producers as land-locked North American crude has, of late, traded at significant discounts to world oil prices. In terms of supply, the Western Canada Sedimentary Basin (WCSB) continues to be viewed as one of the world’s largest and most secure supply sources of crude oil, and production from this region is expected to increase over the long term through continued investment in the Alberta oil sands. Investment in the WCSB has recovered significantly since the period of economic downturn in 2009 and 2010. Several new projects and expansions of existing oil sands production facilities have been added or accelerated due to supportive oil prices and the emergence of increased foreign investment. One of the most fundamental shifts in crude oil supply in recent years is the emergence of shale oil plays. Shale oil plays, such as the Bakken in North Dakota, will be significant contributors to the overall forecasted increase in North American crude production. Increased production from these plays has been facilitated by new drilling and completion methods, which include hydraulic fracturing and horizontal drilling techniques. The substantial growth in North American supply without a corresponding increase in domestic demand has introduced a number of challenges for the industry. In recent years, inventory levels have increased and several transportation bottlenecks have arisen within North America. A notable bottleneck exists in Cushing, Oklahoma, a major pipeline and storage hub, which has experienced heightened receipt of product without commensurate takeaway capacity. The oversupply to this land-locked market has resulted in a divergence between West Texas Intermediate (WTI) and world pricing, resulting in lower netbacks for North American producers than could otherwise be achieved if selling into global markets. In 2012, this price differential ranged from US$10 to as high as US$23 per barrel. For WCSB producers, the oversupply on the continental United States continues to have an adverse effect on heavy crude oil prices from western Canada. With the United States over supplied and with insufficient access to alternative markets, including Asia, heavy crude oil prices for western Canada are expected to remain significantly discounted against WTI. CANADIAN CRUDE OIL PRODUCTION (thousands of barrels per day) Sources: National Energy Board Canadian Association of Petroleum Producers. 13e 12 11 10 Oil Sands Other 2,833 3,628 2,989 3,233

Enbridge’s role in helping to address evolving supply and demand fundamentals, and improving netbacks for producers, is to provide expanded pipeline capacity and sustainable connectivity to alternative markets. In 2012, Enbridge announced a record number of commercially secured projects within Liquids Pipelines to create additional market access solutions and regional oil sands infrastructure. Most notably, the Company’s announced market access initiatives included a $5.8 billion upsized Gulf Coast Access Program, a $2.7 billion Eastern Access Program and a $6.2 billion Light Oil Market Access Program. The Company is developing additional initiatives to access Canadian and United States east coast and eastern Gulf Coast markets. Despite these initiatives, and those of competitors, North American oil prices, including heavy oil prices from western Canada, will likely continue to lag behind world prices, heightening the need for pipeline access to growing Asian markets. Details of the Company’s Northern Gateway, a proposed pipeline system from Alberta to the coast of British Columbia, and associated marine terminal, along with the Company’s other projects under development, can be found in Growth Projects – Commercially Secured Projects and Growth Projects – Other Projects Under Development. SUPPLY AND DEMAND FOR NATURAL GAS Strong growth in North American natural gas production over the past few years has created an oversupplied market and a weak price environment. Although production growth is slowing, North America will continue to be over supplied until significant incremental gas demand arises. North American gas demand has been outpaced by robust supply growth as a prolonged and fragile economic recovery has translated into weak industrial gas demand growth, despite relatively low gas prices. Further, consecutive warm winters have curbed heating demand. In contrast, low gas prices have supported gas-fired power generation as displacement of less competitive coal-fired generation reached unprecedented levels over the past year. Low gas prices are expected to persist, which should enable continued displacement of coal-fired generation. Any future retirement of older, less efficient coal generators could also potentially increase the share of overall power production portfolio held by gas-fired generation. Within Canada, natural gas demand growth is expected to be driven primarily by oil sands development. Strong production growth from shale plays, supported by technological advancements in drilling techniques, has propelled United States domestic gas production to historic highs and has resulted in an enormous resource base. However, as the North American market has become oversupplied, gas prices have weakened and producers have in turn sharply reduced drilling activity except in regions where the gas is rich in NGL. Dry gas production has been supplanted by production from increased rich-gas drilling and associated gas volumes from oil drilling. However, the overall rate of gas production growth has slowed from prior years. In addition, the development of shale plays in close proximity to major gas markets, such as the Marcellus and Utica shale plays in the northeast United States, have been shifting North American gas flows, creating opportunities for new regional infrastructure but also challenges for existing infrastructure serving more traditional supply areas. North American gas prices in 2012 fell to 10-year lows as rising gas production outpaced modest demand growth. While gas prices have recovered somewhat, the expectation is that gas prices will remain relatively low until there is more pervasive demand recovery. NORTH AMERICAN NATURAL GAS PRODUCTION (billions of cubic feet per day) Sources: Energy Information Administration (United States), National Energy Board (Canada), Enbridge research. 13e 12 11 10 Shale Other 73 79 77 79 14 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 15 Similar to crude oil, significant differentials exist between North American and world gas prices. Globally, liquefied natural gas (LNG) is being supplied to meet increasing energy demand as gas supplies in certain regions are abundant and gas is cleaner burning than other forms of hydrocarbons. The price for LNG in the world market is more closely linked to crude prices, providing an opportunity to capture more favourable netbacks on LNG exports from North America. Based on these fundamentals, there is an increasing probability that one or more projects to export LNG off the west Coast of Canada will proceed. The NGL which can be extracted from liquids-rich gas streams include ethane, propane, butane, pentanes plus and natural gasoline, which are used in a variety of industrial, commercial and other applications. Prices for NGL are generally closely correlated with crude oil prices. In the current environment, where the differential between crude oil and natural gas prices is expected to remain historically wide, producers are being incented to shift drilling activity to rich gas regions in order to take advantage of strong NGL fractionation margins. This, in turn, is expected to drive a need for additional midstream processing facilities and transportation solutions to move growing supplies of NGL to market. In response to these evolving natural gas and NGL fundamentals, Enbridge believes it is well positioned to provide value added solutions to producers. Alliance is uniquely configured to transport liquids-rich gas and is currently evaluating service offerings to best meet the needs of producers. The focus on liquids-rich gas development also creates opportunities for Aux Sable, a 50%-owned extraction and fractionation facility near Chicago, Illinois at the terminus of Alliance. Enbridge is also responding to the need for regional infrastructure with additional United States gathering and processing investments and is growing its Canadian midstream business. In addition, Enbridge is a partner in the Texas Express Pipeline (TEP) that will increase NGL pipeline capacity into Mont Belvieu, Texas, with an expected in-service date of mid-2013. SUPPLY AND DEMAND FOR GREEN ENERGY While traditional forms of energy are expected to continue to represent the major source of North American energy supply for the foreseeable future, a shift to a lower carbon-intensive economy has gained momentum. Over the last several years, many large power and infrastructure players, including Enbridge, have increased investment in renewable assets. Enbridge now has interests in more than 1,300 MW of renewable generation capacity. Over the longer term, North American economic growth is anticipated to drive growing electricity consumption. In turn, growing electricity demand is expected to drive new generation capacity growth. The general consensus of energy analysts appears to be that the new generation capacity mix over the next 20 years will shift to lower carbon options such as natural gas or renewable sources of power generation. Although coal and nuclear facilities will continue to provide core electricity generation needs in North America, various emission regulations are anticipated which are expected to force the retirement of aging coal-fired units and restrict the permitting of new coal-fired electrical generation facilities (absent carbon capture and storage technologies). Most North American jurisdictions have also established or are in the process of establishing renewable portfolio standards which mandate the inclusion of a certain proportion of renewable energy generation in their future electricity generation mix. As a result, according to the United States Energy Information Administration, North America is expected to require sizable new generation capacity from alternative sources in order to meet growing electricity demand. Natural gas and renewable energy sources, including biomass, hydro, solar and wind, are likely to play an increasingly important role in the supply of longer-term electricity needs.

The United States National Renewable Energy Laboratory reports that North America has significant wind and solar resources, with wind alone having the potential to provide capacity for over 10,000 gigawatts of power generation. Solar resources in southwestern states such as Arizona, California, Colorado and Nevada are considered by many to be the best in the world for large-scale solar plants. According to Environment Canada, Canada also has an abundance of wind and solar resources, particularly with strong wind resources in the northeastern regions. Expanding renewable energy infrastructure in North America is not without challenges as these high quality wind and solar resources are often found in regions which are not in close proximity to high demand markets, requiring the need for new transmission capacity. To date, the profitability of renewable energy projects has in part been supported by certain tax and government incentives. In the near-term, uncertainty over the continuing availability of tax or other government incentives, and the ability to secure long-term power purchase agreements (PPA) through government or investor-owned power authorities will hinder the pace of future new renewable capacity development. However, over time renewable generation is expected to be competitive with other modes of generation as wind turbine and solar panel costs continue to decline. Enbridge owns nine wind farms and four solar farms, including the recently announced investment in the Massif du Sud Wind Project (Massif du Sud) in Quebec, and will continue to seek new opportunities to grow its portfolio of renewable power generation capacity. As noted, incremental renewable power generation requires increased transmission infrastructure. Enbridge expects to commence operating its first significant power transmission line, running between Montana and Alberta, in 2013, and will continue to seek opportunities to invest in new transmission facilities which meet the Company’s investment criteria. Growth Projects – Commercially Secured Projects In 2012, Enbridge secured a record number of new infrastructure growth projects. In aggregate, the Company added approximately $14 billion of projects across several business units, bringing the total inventory of commercially secured projects to approximately $27 billion. All of these projects are expected to come into service by 2016, and enable the Company to generate industry leading adjusted earnings per share growth over this period. The bulk of new projects secured were within Liquids Pipelines and Sponsored Investments, highlighted by three major new market access initiatives. The $5.8 billion Gulf Coast Access Program, which includes the Seaway Pipeline, the Flanagan South Pipeline Project and elements of the Canadian Mainline and Lakehead System Mainline expansions, is expected to provide capacity for as much as 850,000 barrels per day (bpd) of crude oil to reach the large refinery markets in the Gulf Coast. The $2.7 billion Eastern Access Program is expected to allow for greater access for crude oil into Chicago, further east into Toledo and ultimately into Ontario and Quebec. The Eastern Access Program includes the Company’s Toledo pipeline expansion, Line 9 reversal, the existing Spearhead North pipeline expansion, Line 6B replacement and Line 5 expansion. Finally, the $6.2 billion Light Oil Market Access Program brings together a group of projects to support the increasing supply of light oil from Canada and the Bakken and also supplement the Eastern Access Program through the upsize of the Line 9B and Line 6B capacity expansion. The Light Oil Market Access Program also includes the Southern Access Extension, Canadian Mainline System Terminal Flexibility and Connectivity and twinning of the Spearhead North pipeline and Line 61 expansion included within the Lakehead System Mainline Expansion. These market access initiatives include several mainline system expansion projects which are designed to ensure that there is sufficient capacity to feed these new extensions. 16 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 17 The table below summarizes the current status of the Company’s commercially secured projects, organized by business segment. Estimated Capital Cost 1 Expenditures to Date 2 Expected In-Service Date Status (Canadian dollars, unless stated otherwise) LIQUIDS PIPELINES 1. Edmonton Terminal Expansion $0.2 billion $0.2 billion 2012 Complete 2. Wood Buffalo Pipeline $0.4 billion $0.3 billion 2012 Complete 3. Woodland Pipeline $0.3 billion $0.3 billion 2012 Complete 4. Waupisoo Pipeline Capacity Expansion $0.3 billion $0.3 billion 2012 – 2013 (in phases) Complete 5. Seaway Crude Pipeline System Acquisition/Reversal/Expansion Twinning/Extension US$1.3 billion US$1.1 billion US$1.2 billion US$0.1 billion 2012 – 2013 2014 Complete Pre-construction 6. Suncor Bitumen Blend $0.2 billion $0.1 billion 2013 Under construction 7. Norealis Pipeline $0.5 billion $0.2 billion 2013 Under construction 8. Eddystone Rail Project US$0.1 billion No significant expenditures to date 2013 Pre-construction 9. Athabasca Pipeline Capacity Expansion $0.4 billion $0.2 billion 2013 – 2014 (in phases) Under construction 10. Eastern Access 3 Toledo Expansion Line 9 Reversal US$0.2 billion $0.4 billion US$0.1 billion No significant expenditures to date 2013 2013 – 2014 Under construction Pre-construction 11. Flanagan South Pipeline Project US$2.8 billion US$0.2 billion 2014 Pre-construction 12. Canadian Mainline Expansion $0.6 billion No significant expenditures to date 2014 – 2015 (in phases) Pre-construction 13. Athabasca Pipeline Twinning $1.2 billion No significant expenditures to date 2015 Pre-construction 14. Edmonton to Hardisty Expansion $1.8 billion No significant expenditures to date 2015 Pre-construction 15. Southern Access Extension US$0.8 billion No significant expenditures to date 2015 Pre-construction 16. Canadian Mainline System Terminal Flexibility and Connectivity $0.6 billion No significant expenditures to date 2013 – 2016 (in phases) Pre-construction GAS DISTRIBUTION 17. Greater Toronto Area Project $0.6 billion No significant expenditures to date 2015 Pre-construction GAS PIPELINES, PROCESSING AND ENERGY SERVICES 18. Silver State North Solar Project 4 US$0.2 billion US$0.2 billion 2012 Complete 19. Massif du Sud Wind Project $0.2 billion $0.1 billion 2012 – 2013 Complete 20. Lac Alfred Wind Project $0.3 billion $0.2 billion 2013 (in phases) Under construction 21. Cabin Gas Plant $0.8 billion $0.7 billion To be determined Deferred 22. Peace River Arch Gas Development $0.3 billion $0.1 billion 2012 – 2014 (in phases) Under construction 23. Tioga Lateral Pipeline US$0.1 billion No significant expenditures to date 2013 Under construction 24. Venice Condensate Stabilization Facility US$0.2 billion US$0.1 billion 2013 Under construction 25. Walker Ridge Gas Gathering System US$0.4 billion US$0.1 billion 2014 Pre-construction 26. Big Foot Oil Pipeline US$0.2 billion US$0.1 billion 2014 Pre-construction 27. Heidelberg Lateral Pipeline US$0.1 billion No significant expenditures to date 2016 Pre-construction

Estimated Capital Cost 1 Expenditures to Date 2 Expected In-Service Date Status (Canadian dollars, unless stated otherwise) SPONSORED INVESTMENTS 28. EEP – Bakken Expansion Program US$0.3 billion US$0.2 billion 2013 Substantially complete 29. The Fund – Bakken Expansion Program $0.2 billion $0.1 billion 2013 Substantially complete 30. EEP – Berthold Rail Project US$0.1 billion US$0.1 billion 2013 Under construction 31. EEP – Ajax Cryogenic Processing Plant US$0.2 billion US$0.2 billion 2013 Under construction 32. EEP – Cushing Terminal Storage Expansion Project US$0.2 billion US$0.1 billion 2012 – 2013 (in phases) Under construction 33. EEP – South Haynesville Shale Expansion US$0.3 billion US$0.2 billion 2012+ (in phases) Under construction 34. EEP – Bakken Access Program US$0.1 billion US$0.1 billion 2013 Under construction 35. EEP – Texas Express Pipeline US$0.4 billion US$0.2 billion 2013 Under construction 36. EEP – Line 6B 75-Mile Replacement Program US$0.3 billion US$0.2 billion 2013 Under construction 37. EEP – Eastern Access US$2.6 billion US$0.3 billion 2013 – 2016 (in phases) Pre-construction 38. EEP – Lakehead System Mainline Expansion US$2.4 billion No significant expenditures to date 2014 – 2016 (in phases) Pre-construction 39. EEP – Sandpiper Project US$2.5 billion No significant expenditures to date 2016 Pre-construction CORPORATE 40. Montana-Alberta Tie-Line US$0.4 billion US$0.3 billion 2013 – 2014 (in stages) Under construction 1 These amounts are estimates and subject to upward or downward adjustment based on various factors. As appropriate, the amounts reflect Enbridge’s share of joint venture projects. 2 Expenditures to date reflect total cumulative expenditures incurred from inception of project up to December 31, 2012. 3 See Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Eastern Access for project discussion. 4 Expenditures to date reflect total expenditures before receipt of US$55 million payment from the United States Treasury. See Growth Projects – Commercially Secured Projects – Gas Pipelines, Processing and Energy Services – Silver State North Solar Project. Risks related to the development and completion of growth projects are described under Risk Management and Financial Instruments – General Business Risks. LIQUIDS PIPELINES EDMONTON TERMINAL EXPANSION The Edmonton Terminal Expansion Project involved expanding the tankage of the mainline terminal at Edmonton, Alberta. The expansion was required to accommodate growing oil sands production receipts both from Enbridge’s Waupisoo Pipeline and other non-Enbridge pipelines. Construction was completed and the project was placed into service in December 2012, adding four tanks, three booster pumps and related infrastructure, and expanding the tankage of the mainline terminal by one million barrels. The project was completed under budget with a final cost of approximately $0.2 billion. 18 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 19 1 3 2 4 5 7 6 10 15 12 9 11 13 14 16 8 Toledo Superior Patoka Wood River Chicago Hardisty Fort McMurray Zama Norman Wells Edmonton Blaine Portland Salt Lake City Casper Cushing Houston New Orleans Montreal Toronto Sarnia 9 Athabasca Pipeline Capacity Expansion 10 Eastern Access (Toledo expansion and Line 9 reversal) 11 Flanagan South Pipeline Project 12 Canadian Mainline Expansion 13 Athabasca Pipeline Twinning 14 Edmonton to Hardisty Expansion 15 Southern Access Extension 16 Canadian Mainline System Terminal Flexibility and Connectivity Current Assets Growth Opportunities Liquids Pipelines 1 Edmonton Terminal Expansion 2 Wood Buffalo Pipeline 3 Woodland Pipeline 4 Waupisoo Pipeline Capacity Expansion 5 Seaway Crude Pipeline System (including acquisition, reversal, expansion, twinning and extension) 6 Suncor Bitumen Blend 7 Norealis Pipeline 8 Eddystone Rail Project F ior erio io e pe up uperio To n rn arn a ic Ch C a Pa Riv g N

WOOD BUFFALO PIPELINE Under an agreement with Suncor Energy Inc. (Suncor), Enbridge constructed a new, 95-kilometre (59-mile), 30-inch diameter crude oil pipeline, connecting the Athabasca Terminal, adjacent to Suncor’s oil sands plant, to the Cheecham Terminal, which is the origin point of Enbridge’s Waupisoo Pipeline. The Waupisoo Pipeline delivers crude oil from several oil sands projects to the Edmonton, Alberta mainline hub. The new Wood Buffalo Pipeline was placed into service in October 2012 and it parallels the existing Athabasca Pipeline. Additional expenditures will be incurred in 2013 and the estimated capital cost remains at approximately $0.4 billion, with expenditures to date of approximately $0.3 billion. WOODLAND PIPELINE Enbridge entered into a joint venture agreement with Imperial Oil Resources Ventures Limited and ExxonMobil Canada Properties to provide for the transportation of blended bitumen from the Kearl oil sands mine to crude oil hubs in the Edmonton, Alberta area. The project is being phased with the mine expansion, with the first phase involving construction of a new 140-kilometre (87-mile) 36-inch diameter pipeline from the mine to the Cheecham Terminal, and service on Enbridge’s existing Waupisoo Pipeline from Cheecham to the Edmonton area. The total estimated cost of the Phase I pipeline from the mine to the Cheecham Terminal and related facilities is approximately $0.5 billion, of which Enbridge’s share is approximately $0.3 billion. Enbridge’s share of total project expenditures to date is approximately $0.3 billion. Although the completed pipeline was available for service in November 2012, Enbridge expects the pipeline will be placed into service in the first quarter of 2013, commensurate with the start-up of the Kearl oil sands mine. WAUPISOO PIPELINE CAPACITY EXPANSION The Waupisoo Pipeline Capacity Expansion provided 65,000 bpd of additional capacity in the fourth quarter of 2012. Two stations that will provide a further 190,000 bpd of additional capacity have been completed and are anticipated to be placed into service in the third quarter of 2013 when they are expected to be required to accommodate additional throughput. The total cost of the project was approximately $0.3 billion. SEAWAY CRUDE PIPELINE SYSTEM ACQUISITION OF INTEREST In 2011, Enbridge acquired a 50% interest in the Seaway Pipeline at a cost of approximately US$1.2 billion. Seaway Pipeline includes the 805-kilometre (500-mile), 30-inch diameter long-haul system from Freeport, Texas to Cushing, Oklahoma. For further details about Seaway Pipeline refer to Liquids Pipelines – Seaway Pipeline. REVERSAL AND EXPANSION The flow direction of the Seaway Pipeline has been reversed, enabling it to transport crude oil from the oversupplied hub in Cushing, Oklahoma to the Gulf Coast. The initial reversal of the pipeline and preliminary service commenced in the second quarter of 2012, providing initial capacity of 150,000 bpd. Further pump station additions and modifications were completed in January 2013, increasing capacity available to shippers to up to approximately 400,000 bpd, depending on crude slate. Actual throughput experienced to date in 2013 has been curtailed due to constraints on third party takeaway facilities. A lateral from the Seaway Jones Creek tankage to the ECHO crude oil terminal in Houston, Texas should eliminate these constraints when it comes into service, expected in the fourth quarter of 2013. 20 < ENBRIDGE INC. 2012 FINANCIAL REPORT O O EST S R ER TE F AC U Q NT T RES TER I ON TIO TI SIT IS RSA S O REV PA XPA D R AN EX R ER A A A SA VE VER N SIO ANS EXP AL

Management’s Discussion and Analysis > 21 TWINNING AND EXTENSION In March 2012, based on additional capacity commitments from shippers, plans were announced to proceed with an expansion of the Seaway Pipeline through construction of a second line that is expected to more than double its capacity to 850,000 bpd in mid-2014. This 30-inch diameter pipeline will follow the same route as the existing Seaway system. Included in the project scope is a 105-kilometre (65-mile), 36-inch new-build lateral from the Seaway Jones Creek facility southwest of Houston, Texas into Enterprise Product Partners L.P.’s (Enterprise) ECHO crude oil terminal (ECHO Terminal) southeast of Houston. In addition, a 137-kilometre (85-mile) pipeline will be constructed from the ECHO Terminal to the Port Arthur/ Beaumont, Texas refining center to provide shippers access to the region’s heavy oil refining capabilities. This extension will offer capacity of 560,000 bpd and, subject to regulatory approvals, is expected to be available in the first quarter of 2014. Including the acquisition of the 50% interest in the Seaway Pipeline, Enbridge’s total expected cost for the Seaway Pipeline is approximately US$2.4 billion. The acquisition, reversal and expansion are expected to cost US$1.3 billion, with the twinning, extension and lateral to the ECHO Terminal components of the project expected to cost approximately US$1.1 billion. Total expenditures incurred to date were approximately US$1.3 billion. SUNCOR BITUMEN BLEND In September 2012, Enbridge entered into an agreement with Suncor for a Bitumen Blend project, which includes the construction of a new 350,000 barrel tank, new blend and diluent lines and pumping capacity to connect with Suncor’s lines just outside Enbridge’s Athabasca Tank Farm. These new facilities will enable Suncor to transport blended bitumen volumes from its Firebag production into the Wood Buffalo pipeline. The estimated cost for the project is approximately $0.2 billion, with expenditures to date of approximately $0.1 billion. The Bitumen Blend project is expected to be in-service in the second quarter of 2013. SOUTH CHEECHAM RAIL AND TRUCK TERMINAL The Company has partnered with Keyera Corp. to construct the South Cheecham Rail and Truck Terminal (the Terminal), located approximately 75 kilometres (47 miles) southeast of Fort McMurray, Alberta. The Terminal, to be developed in phases, will be a multi-purpose hydrocarbon rail and truck terminal, designed to support bitumen producers within the Athabasca oil sands area and facilitate product in and out. In addition to the facilities for handling diluent and diluted bitumen at the Terminal, the initial phase is planned to include a diluted bitumen pipeline connection to Enbridge’s existing Cheecham Terminal. Construction is underway and completion of the first phase is expected to take place in the second quarter of 2013 for a total cost of approximately $90 million. Enbridge’s share of the project costs will be based upon its 50% joint venture interest. NOREALIS PIPELINE In order to provide pipeline and terminaling services to the proposed Husky Energy Inc. operated Sunrise Oil Sands Project, the Company is undertaking construction of a new originating terminal (Norealis Terminal), a 112-kilometre (66-mile) 24-inch diameter pipeline from the Norealis Terminal to the Cheecham Terminal, and additional tankage at Cheecham. The estimated cost of the project is approximately $0.5 billion, with expenditures to date of approximately $0.2 billion. The project is expected to be available for service by the end of 2013. O D TE EX EXT A S N TEN N SIO ENS AN G NG I N WI TW

EDDYSTONE RAIL PROJECT In November 2012, the Company announced that it had entered into a joint venture agreement with Canopy Prospecting Inc. to develop a unit-train unloading facility and related local pipeline infrastructure near Philadelphia, Pennsylvania to deliver Bakken and other light sweet crude oil to Philadelphia area refineries. The Eddystone Rail Project will include leasing portions of a power generation facility and reconfiguring existing track to accommodate 120-car unit-trains, installing crude oil offloading equipment, refurbishing an existing 200,000 barrel tank and upgrading an existing barge loading facility. Subject to regulatory and other approvals, the project is expected to be placed into service by the end of 2013 to receive and deliver an initial capacity of 80,000 bpd, expandable to 160,000 bpd. The total estimated cost of the project is approximately US$68 million and Enbridge’s share of the project costs will be based upon its 75% joint venture interest. ATHABASCA PIPELINE CAPACITY EXPANSION The Company is undertaking an expansion of its Athabasca Pipeline to its full capacity to accommodate additional contractual commitments, including incremental production from the Christina Lake Oilsands Project operated by Cenovus Energy Inc. This expansion is expected to increase the capacity of the Athabasca Pipeline to its maximum capacity of approximately 570,000 bpd, depending on the mix of crude oil types. The estimated cost of the entire expansion is approximately $0.4 billion, with expenditures to date of approximately $0.2 billion. The initial expansion to 430,000 bpd of capacity is expected to be placed into service by the end of the first quarter of 2013. The balance of additional capacity is expected to be available by early 2014. The Athabasca Pipeline transports crude oil from various oil sands projects to the mainline hub at Hardisty, Alberta. FLANAGAN SOUTH PIPELINE PROJECT The 950-kilometre (590-mile) Flanagan South Pipeline will have an initial capacity of approximately 585,000 bpd to transport crude oil from the Company’s terminal at Flanagan, Illinois to Cushing, Oklahoma. The 36-inch diameter pipeline will be installed adjacent to the Company’s Spearhead Pipeline for the majority of the route. Subject to regulatory and other approvals, the pipeline is expected to be in service by mid-2014. The estimated cost of the project is approximately US$2.8 billion, with expenditures to date of approximately US$0.2 billion. CANADIAN MAINLINE EXPANSION In May 2012, Enbridge announced an estimated $0.2 billion expansion of the Alberta Clipper line between Hardisty, Alberta and the Canada/United States border near Gretna, Manitoba. The current scope of the project involves the addition of pumping horsepower sufficient to raise the capacity of the Alberta Clipper line by 120,000 bpd to a capacity of 570,000 bpd and is expected to be in service by mid-2014. The expansion remains subject to National Energy Board (NEB) approval. In January 2013, Enbridge announced a further expansion of the Canadian Mainline system between Hardisty, Alberta and the Canada/United States border near Gretna, Manitoba, at an estimated cost of $0.4 billion, bringing the total expected cost for the expansion to approximately $0.6 billion. Subject to NEB approval, the current scope of the additional expansion involves the addition of pumping horsepower sufficient to raise the capacity of the Alberta Clipper line by another 230,000 bpd to its full capacity of 800,000 bpd. This component of the expansion is expected to be in service in 2015. ATHABASCA PIPELINE TWINNING This project involves the twinning of the southern section of the Company’s Athabasca Pipeline from Kirby Lake, Alberta to the Hardisty, Alberta crude oil hub to provide additional capacity to serve expected oil sands growth in the Kirby Lake producing region. The expansion project, with an estimated cost of approximately $1.2 billion, will include 345 kilometres (210 miles) of 36-inch pipeline adjacent to the existing Athabasca Pipeline right-of-way. The initial annual capacity of the pipeline will be approximately 450,000 bpd, with expansion potential to 800,000 bpd. The line is expected to enter service in 2015. 22 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 23 EDMONTON TO HARDISTY EXPANSION In November 2012, the Company announced plans to proceed with an expansion of the Canadian Mainline system between Edmonton, Alberta and Hardisty, Alberta. The expansion project, with an estimated cost of approximately $1.8 billion, will include 181 kilometres (112 miles) of new 36-inch diameter pipeline, expected to generally follow the same route as Enbridge’s existing Line 4 pipeline, and new terminal facilities at Edmonton which include five new 500,000 barrel tanks and connections into existing infrastructure at Hardisty Terminal. The initial capacity of the new line is expected to be approximately 570,000 bpd, with expansion potential to 800,000 bpd. Subject to regulatory approvals, the project is expected to be placed into service in 2015. SOUTHERN ACCESS EXTENSION In December 2012, Enbridge announced that it will undertake the Southern Access Extension project, which will consist of the construction of a new 265-kilometre (165-mile), 24-inch diameter crude oil pipeline from Flanagan to Patoka, Illinois as well as additional tankage and two new pump stations. Subject to regulatory approval, the project is expected to be placed into service in 2015 at an approximate cost of US$0.8 billion. The initial capacity of the new line is expected to be approximately 300,000 bpd. The Company also announced a binding open season to solicit commitments from shippers for capacity on the proposed pipeline. The open season closed in January 2013 and the Company is evaluating the results. Prior to launching the open season, Enbridge had already received sufficient capacity commitments from an anchor shipper to support the 24-inch pipeline as proposed. CANADIAN MAINLINE SYSTEM TERMINAL FLEXIBILITY AND CONNECTIVITY In December 2012, as part of the Light Oil Market Access Program initiative, the Company announced that it will undertake the Canadian Mainline System Terminal Flexibility and Connectivity project in order to accommodate additional light oil volumes and enhance the operational flexibility of the Canadian mainline terminals. The cost of the project is expected to be approximately $0.6 billion, with varying completion dates between 2013 and 2016 related to existing terminal facility modifications, comprised of upgrading existing booster pumps, additional booster pumps and new tank line connections. GAS DISTRIBUTION GREATER TORONTO AREA PROJECT In September 2012, EGD announced plans to expand its natural gas distribution system in the Greater Toronto Area (GTA) to meet the demands of growth and continue the safe and reliable delivery of natural gas to current and future customers. At an expected cost of approximately $0.6 billion, the proposed GTA project will consist of two segments of pipeline and related facilities to upgrade the existing distribution system that delivers natural gas to several municipalities in Ontario. In December 2012, the Company filed an application with the Ontario Energy Board (OEB), and, subject to OEB approval, construction is targeted to start in 2014, with completion expected by the end of 2015. New York Ontario 17 Toronto Quebec Gas Distribution 17 Greater Toronto Area Project

GAS PIPELINES, PROCESSING AND ENERGY SERVICES SILVER STATE NORTH SOLAR PROJECT In March 2012, Enbridge secured a 100% interest in the development of the 50-MW Silver State, located 65 kilometres (40 miles) south of Las Vegas, Nevada. The project, which began commercial operation in May 2012, was constructed under a fixed-price engineering, procurement and construction agreement with First Solar. First Solar is providing operations and maintenance services under a long-term contract. Energy output is being delivered to NV Energy, Inc. under a 25-year PPA. The Company’s total investment in the project was approximately US$0.2 billion. In October 2012, the Company received a US$55 million payment from the United States Treasury under a program which reimburses eligible applicants for a portion of costs related to installing specified renewable energy property. MASSIF DU SUD WIND PROJECT In December 2012, Enbridge secured a 50% interest in the 150-MW Massif du Sud development, located 100 kilometres (60 miles) east of Quebec City, Quebec. Project construction was completed in December 2012 and commercial operation commenced in January 2013. Massif du Sud delivers energy to Hydro-Quebec under a 20-year PPA. The Company’s total investment in the project is approximately $0.2 billion with expenditures to date of approximately $0.1 billion. Additional expenditures are expected to be incurred into 2013. LAC ALFRED WIND PROJECT Enbridge secured a 50% interest in the development of the 300-MW Lac Alfred Wind Project (Lac Alfred), located 400 kilometres (250 miles) northeast of Quebec City in Quebec’s Bas-Saint-Laurent region. The project is being constructed under a fixed price, turnkey, engineering, procurement and construction agreement and is being undertaken in two phases. Phase 1, providing 150-MW, was completed and commenced commercial operations in January 2013, with Phase 2, for the remaining 150-MW, expected to be completed in the third quarter of 2013. Lac Alfred is delivering energy to Hydro-Quebec under a 20-year PPA. The Company’s total investment in the project is expected to be approximately $0.3 billion, with expenditures to date of approximately $0.2 billion. CABIN GAS PLANT In 2011, the Company secured a 71% interest in the development of the Cabin Gas Plant (Cabin), located 60 kilometres (37 miles) northeast of Fort Nelson, British Columbia in the Horn River Basin. The Company’s total investment in phases 1 and 2 of Cabin was expected to be approximately $1.1 billion. In October 2012, the Company and its partners announced plans to defer both the commissioning of phase 1 and the construction of phase 2. In December 2012, Enbridge began earning fees for its investment made to date in both phases 1 and 2. Under the deferral, the Company’s total investment in phases 1 and 2 is now expected to be approximately $0.8 billion, with expenditures to date of approximately $0.7 billion. Additional expenditures related to the deferral will continue to be incurred in 2013. PEACE RIVER ARCH GAS DEVELOPMENT In November 2012, the Company completed the acquisition from Encana Corporation (Encana) of certain sour gas gathering and compression facilities. These facilities, which are either currently in service or under construction, are located in the PRA region of northwest Alberta. The project will be completed in phases with new gathering lines expected to be in service in late 2013 and new NGL handling facilities expected to be completed in first quarter of 2014. Enbridge’s investment in the PRA Gas Development is expected to be approximately $0.3 billion, with expenditures to date of approximately $0.1 billion. Enbridge is also working exclusively with Encana on facility scoping for development of additional major midstream facilities in the liquids-rich PRA region. Financial terms of the PRA Gas Development are expected to be substantially consistent with previously established terms of the Cabin development. 24 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 25 24 18 25 19 20 21 22 27 26 23 Toledo Sarnia Superior Chicago Hardisty Fort McMurray Fort St. John Edmonton Cushing Houston New Orleans Denver Quebec City Toronto Gas Pipelines, Processing and Energy Services 18 Silver State North Solar Project 19 Massif du Sud Wind Project 20 Lac Alfred Wind Project 21 Cabin Gas Plant 22 Peace River Arch Gas Development Current Assets Growth Opportunities 23 Tioga Lateral Pipeline 24 Venice Condensate Stabilization Facility 25 Walker Ridge Gas Gathering System 26 Big Foot Oil Pipeline 27 Heidelberg Lateral Pipeline io ior eri e pe uperio i n rn a Sa S ia nia r ar ic

TIOGA LATERAL PIPELINE Alliance Pipeline US is constructing a natural gas pipeline lateral and associated facilities to connect production from the Hess Tioga field processing plant in the Bakken region of North Dakota to the Alliance mainline near Sherwood, North Dakota. The 124-kilometre (77-mile) Tioga Lateral Pipeline will facilitate movement of liquids-rich natural gas to NGL processing facilities owned by Aux Sable at the terminus of Alliance. The pipeline will have an initial design capacity of approximately 106 million cubic feet per day (mmcf/d), which can be expanded based on shipper demand. Through its 50% ownership interest in Alliance Pipeline US, Enbridge’s expected cost related to the project is approximately US$0.1 billion. In October 2012, Alliance Pipeline US executed a contract with Hess Corporation (Hess) as an anchor shipper. Aux Sable Liquids Products and Hess have reached a concurrent agreement for the provision of NGL services. Regulatory approval from the Federal Energy Regulatory Commission (FERC) was received in September 2012 and construction commenced early October 2012, with an expected third quarter 2013 in-service date. VENICE CONDENSATE STABILIZATION FACILITY The Company is carrying out an estimated US$0.2 billion expansion of the Venice Condensate Stabilization Facility (Venice) at its Venice, Louisiana facility within its Offshore business. Expenditures to date are approximately US$0.1 billion. The expanded condensate processing capacity is required to accommodate additional natural gas production from the Olympus offshore oil and gas development. Natural gas production from Olympus will move to Enbridge’s onshore facility at Venice via Enbridge’s Mississippi Canyon offshore pipeline system where it will be processed to separate and stabilize the condensate. The expansion, which is expected to more than double the capacity of the facility to approximately 12,000 barrels of condensate per day, is expected to be in service in late 2013. WALKER RIDGE GAS GATHERING SYSTEM The Company executed definitive agreements in 2010 with Chevron USA, Inc. (Chevron) and Union Oil Company of California to expand its central Gulf of Mexico offshore pipeline system. Under the terms of the agreements, Enbridge will construct, own and operate the Walker Ridge Gas Gathering System (WRGGS) to provide natural gas gathering services to the proposed Jack, St. Malo and Big Foot ultra-deep water developments. The WRGGS includes 274 kilometres (170 miles) of 8-inch or 10-inch diameter pipeline at depths of up to approximately 2,150 meters (7,000 feet) with capacity of 0.1 billion cubic feet per day (bcf/d). WRGGS is expected to be in service in 2014 and is expected to cost approximately US$0.4 billion, with expenditures to date of approximately US$0.1 billion. BIG FOOT OIL PIPELINE The Company executed definitive agreements in 2011 with Chevron, Statoil Gulf of Mexico LLC and Marubeni Oil & Gas (USA) Inc. to construct and operate a 64-kilometre (40-mile) 20-inch oil pipeline with capacity of 100,000 bpd from the proposed Big Foot ultra-deep water development in the Gulf of Mexico. This crude oil pipeline project is complementary to Enbridge’s plans to construct the WRGGS. The estimated cost of the Big Foot Oil Pipeline, which will be located about 274 kilometres (170 miles) south of the coast of Louisiana, is approximately US$0.2 billion, with expenditures to date of approximately US$0.1 billion. This project is expected to be in service in 2014. HEIDELBERG LATERAL PIPELINE In November 2012, Enbridge announced it will build, own and operate a crude oil pipeline in the Gulf of Mexico to connect the proposed Heidelberg development, operated by Anadarko Petroleum Corporation (Anadarko), to an existing third-party system. The Heidelberg Lateral Pipeline (Heidelberg), a 20-inch, 55-kilometre (34-mile) pipeline, will originate in Green Canyon Block 860, approximately 320 kilometres (200 miles) southwest of New Orleans, Louisiana, and in an estimated 1,600 metres (5,300 feet) of water. Subject to regulatory and other approvals, as well as sanctioning of the development by Anadarko and its project co-owners, Heidelberg is expected to be operational by 2016 at an approximate cost of US$0.1 billion. 26 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 27 SPONSORED INVESTMENTS BAKKEN EXPANSION PROGRAM A joint project to further expand crude oil pipeline capacity to accommodate growing crude oil production from the Bakken and Three Forks formations located in Montana, North Dakota, Saskatchewan and Manitoba is being undertaken by EEP and the Fund. Upon completion, which is expected in the first quarter of 2013, and subject to NEB approval, the Bakken Expansion Program will provide capacity of 145,000 bpd. The United States component is being undertaken by EEP and the Canadian component is being undertaken by the Fund. The estimated capital cost for the Canadian portion remains at approximately $0.2 billion, with expenditures incurred to the end of December 2012 of approximately $0.1 billion. The estimated capital cost for the United States portion of the project is now approximately US$0.3 billion, with expenditures incurred to the end of December 2012 of approximately US$0.2 billion. ENBRIDGE ENERGY PARTNERS, L.P. BERTHOLD RAIL PROJECT The Berthold Rail project will expand capacity into the Berthold Terminal by 80,000 bpd and includes the construction of a three-unit train loading facility, crude oil tankage and other terminal facilities adjacent to existing infrastructure. The first phase of terminal facilities was completed in September 2012, providing additional capacity of 10,000 bpd to the Berthold Terminal. The loading facility and crude oil tankage are expected to be placed into service in the first quarter of 2013. The estimated cost of the project is approximately US$0.1 billion, with project expenditures to date of approximately US$0.1 billion. AJAX CRYOGENIC PROCESSING PLANT EEP is constructing an additional natural gas processing plant and other facilities on its Anadarko System. The Ajax Plant, with a planned capacity of 150 mmcf/d, is expected to be in service mid-2013. When operational, the Ajax Plant, in conjunction with the Allison Plant, is expected to increase total processing capacity on the Anadarko System to approximately 1,200 mmcf/d. The estimated cost of the project is approximately US$0.2 billion, with expenditures to date of approximately US$0.2 billion. CUSHING TERMINAL STORAGE EXPANSION PROJECT EEP has completed construction and placed into service 13 new crude oil storage tanks at its Cushing Terminal with an approximate shell capacity of 4.4 million barrels. With five tanks completed in 2011, the remaining eight tanks were placed into service throughout 2012. In July 2012, engineering design commenced on an additional three new tanks and associated infrastructure totaling 936,000 barrels of incremental shell capacity at EEP’s Cushing Terminal, at an estimated cost of US$39 million. The expected in-service date for the three tanks is now the fourth quarter of 2013. The total estimated cost to construct the 16 storage tanks and infrastructure, as required, is approximately US$0.2 billion, with expenditures to date of approximately US$0.1 billion. SOUTH HAYNESVILLE SHALE EXPANSION EEP has expanded its East Texas natural gas pipeline system by constructing three lateral pipelines into the East Texas portion of the Haynesville shale, together with a large diameter lateral pipeline from Shelby County to Carthage. The expansion, completed in the second quarter of 2012 at an approximate cost of US$0.1 billion, increased capacity of EEP’s East Texas system by 900 mmcf/d. O O B P D LD R PR A RA R ERT CT OJ BER T EC L AI L THO TH O YO O P P SS R PR R CRY T A A LA A JA C C ES C AJA N EN ANT PL G SI CES IC G AX O O ST CT O G P PA XPA S R ER TER R PR RA EXPA A A NA S CUS OJ ANS AG AL T EC ON SI EX E TO I RM TE NG I SH O S S ESV O PA XPA HA EX LE A A HA A HAY S UT AL LL ESVI N SIO ANS EXP SHA LE L VI YN AYN TH

34 28 29 31 32 33 30 35 37 38 39 36 38 Toledo Sarnia Toronto Superior Flanagan Chicago Hardisty Edmonton Cushing Houston New Orleans Sponsored Investments 28 EEP – Bakken Expansion Program 29 The Fund – Bakken Expansion Program 30 EEP – Berthold Rail Project 31 EEP – Ajax Cryogenic Processing Plant 32 EEP – Cushing Terminal Storage Expansion Project 33 EEP – South Haynesville Shale Expansion Current Assets Growth Opportunities 34 EEP – Bakken Access Program 35 EEP – Texas Express Pipeline 36 EEP – Line 6B 75-Mile Replacement Program 37 EEP – Eastern Access 38 EEP – Lakehead System Mainline Expansion 39 EEP – Sandpiper Project 28 < ENBRIDGE INC. 2012 FINANCIAL REPORT Ch

Management’s Discussion and Analysis > 29 EEP plans to invest an additional US$0.2 billion, with expenditures to date of approximately US$0.1 billion, to expand its East Texas system, including the construction of gathering and related treating facilities. EEP has signed long-term agreements with four major natural gas producers along the Texas side of the Haynesville shale to provide gathering, treating and transmission services. Completion of the additional expansion is dependent on drilling plans of these producers. Due to lower levels of producer activity in response to weak natural gas prices, EEP has deferred portions of its Haynesville natural gas expansion pending increases in drilling activity. BAKKEN ACCESS PROGRAM The Bakken Access Program represents an upstream expansion that will further complement EEP’s Bakken expansion. This expansion program will enhance crude oil gathering capabilities on the North Dakota System by 100,000 bpd. The program involves increasing pipeline capacity, constructing additional storage tanks and adding truck access facilities at multiple locations in western North Dakota at an approximate cost of US$0.1 billion, with expenditures to date of approximately US$0.1 billion. The Bakken Access Program is expected to be in service by mid-2013. TEXAS EXPRESS PIPELINE The TEP is a joint venture with Enterprise, Anadarko and DCP Midstream LLC to design and construct a new NGL pipeline and two new NGL gathering systems which EEP will build and operate. EEP will invest approximately US$0.4 billion in the TEP, which will originate in Skellytown, Texas and extend approximately 935 kilometres (580 miles) to NGL fractionation and storage facilities in Mont Belvieu, Texas. Expenditures to date are approximately US$0.2 billion. TEP is expected to have an initial capacity of approximately 280,000 bpd and will be expandable to approximately 400,000 bpd. Approximately 250,000 bpd of capacity has been subscribed on the pipeline. One of the new NGL gathering systems will connect TEP to natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle and western Oklahoma, while the second will connect TEP to central Texas Barnett Shale processing plants. Subject to regulatory approvals and finalization of commercial terms, the pipeline and portions of the gathering systems are expected to begin service in the third quarter of 2013. LINE 6B 75-MILE REPLACEMENT PROGRAM This program includes the replacement of 120 kilometres (75 miles) of non-contiguous sections of Line 6B of EEP’s Lakehead System. The Line 6B pipeline runs from Griffith, Indiana through Michigan to the international border at the St. Clair River. The new segments are expected to be placed in service during 2013 in consultation with, and to minimize impact to, refiners and shippers served by Line 6B crude oil deliveries. These costs will be recovered through EEP’s tariff surcharge that is part of the system-wide rates for the Lakehead System. The total capital for this replacement program is estimated to be US$0.3 billion, with expenditures to date of approximately US$0.2 billion. EASTERN ACCESS The Eastern Access initiative includes several crude oil pipeline projects announced by Enbridge and EEP in 2011 and 2012 to provide increased access to refineries in the United States upper mid-west and eastern Canada. The current scope of Enbridge projects includes a reversal of its Line 9 and expansion of the Toledo Pipeline. The current scope of EEP projects includes an expansion of its Line 5 as well as United States mainline system expansions involving the Spearhead North Pipeline (Line 62) and further segments of Line 6B. The individual projects are further described below. Enbridge plans to reverse a portion of its Line 9A in western Ontario to permit crude oil movements eastbound from Sarnia as far as Westover, Ontario at a revised estimated cost of approximately $48 million. With NEB approval received in July 2012, the Line 9A reversal is expected to be in service in late 2013. O SS ES A RA A KEN P BA R PR A BAKK ACC EN G AM CES KKE P P P XPR PR EXA XA SS ES AS E N LI EL PEL PI RES EXP EX TEX TE AC O LI P P EP B R GRA 75 6 R PR R G - A RA A LA 5 L L AM T ENT EN EM CEM PL REP LE I M E N SS CES R ER ES A A EA AC AST C RN TER TE

Enbridge also plans to undertake a full reversal of its 240,000 bpd Line 9B from Westover, Ontario to Montreal, Quebec to serve refineries in Quebec. The Line 9B reversal is expected to be completed at an estimated cost of approximately $0.3 billion. Following an open season held on the Line 9B reversal project, further commitments were received that required an additional 80,000 bpd of delivery capacity within Ontario and Quebec. The Line 9B capacity expansion is expected to be completed at an estimated cost of approximately $0.1 billion. Subject to NEB regulatory approval, the Line 9B reversal and Line 9B capacity expansion are expected to be available for service in 2014 at a total estimated cost of approximately $0.4 billion. Enbridge is also undertaking an 80,000 bpd expansion of its Toledo Pipeline (Line 17), which connects with the EEP mainline at Stockbridge, Michigan and serves refineries at Toledo, Ohio and Detroit, Michigan. The Toledo Pipeline expansion is expected to be available for service by the second quarter of 2013 at a cost of approximately US$0.2 billion, with expenditures to date of approximately US$0.1 billion. Both the Toledo Pipeline and Line 9 assets are included in the Company’s Liquids Pipelines segment. EEP is expanding its Line 5 light crude oil line between Superior, Wisconsin and Sarnia, Ontario by 50,000 bpd, at a cost of approximately US$0.1 billion. The Line 5 expansion is targeted to be in service during the first quarter of 2013. EEP is also undertaking the expansion of its Line 62 between Flanagan and Griffith, Indiana by adding horsepower to increase capacity from 130,000 bpd to 235,000 bpd and adding a 330,000 barrel tank at Griffith. The Line 62 capacity expansion project is expected to be placed into service by the end of 2013. EEP also plans to replace additional sections of Line 6B in Indiana and Michigan to increase capacity from 240,000 bpd to 500,000 bpd, with a target in-service date of early 2014. The replacement of these sections of Line 6B is in addition to the Line 6B Replacement Program announced in 2011 and discussed previously. The expected cost of the United States mainline expansions is US$2.2 billion, and includes the US$0.1 billion cost of the previously discussed Line 5 expansion. In December 2012, Enbridge and EEP announced a further upsizing of EEP’s Line 6B component of the Eastern Access Expansion initiative. The Line 6B capacity expansion from Griffith to Stockbridge, Michigan will increase capacity from 500,000 bpd to 570,000 bpd and will involve the addition of new pumps, existing station modifications and breakout tankage at the Griffith and Stockbridge terminals. Subject to regulatory and other approvals, the project is expected to be placed into service in 2016 at an estimated capital cost of approximately US$0.4 billion. The total estimated cost of the United States mainline expansions, including the Line 6B capacity expansion project, is approximately US$2.6 billion, with expenditures to date of approximately US$0.3 billion. The Eastern Access projects will be funded 60% by Enbridge and 40% with EEP having the option to reduce its funding and associated economic interest in the project by up to 15% before June 30, 2013. Furthermore, within one year of the final in-service date of the collective projects, EEP will have the option to increase its economic interest held at that time by up to 15%. LAKEHEAD SYSTEM MAINLINE EXPANSION In 2012, Enbridge and EEP announced several projects to expand capacity of the Lakehead System mainline between its origin at the Canada/United States border, near Neche, North Dakota, to Flanagan, Illinois. Included in the expansion are Alberta Clipper (Line 67) and Southern Access (Line 61). The current scope of the Alberta Clipper expansion between the border and Superior, Wisconsin consists of two phases. The initial phase, announced in May 2012, includes a planned increase in capacity from 450,000 bpd to 570,000 bpd at an estimated capital cost of approximately US$0.2 billion. In January 2013, EEP announced a further expansion of the Lakehead System mainline between the border and Superior, to increase capacity from 570,000 bpd to 800,000 bpd, at an estimated capital cost of approximately US$0.2 billion. Subject to finalization of scope and regulatory and shipper approvals, including an amendment to the current Presidential border crossing permit to allow for operation of Line 67 at its currently planned operating capacity of 800,000 bpd, the target in-service dates for the proposed projects are mid-2014 for the initial phase and 2015 for the second phase. Both phases of the Alberta Clipper expansion would require only the addition of pumping horsepower and no pipeline construction. 30 < ENBRIDGE INC. 2012 FINANCIAL REPORT SY S YST O PA XPA D AD A A LA TEM YS A MA A EA N KEH L ON SIO ANS EXP EX E LI L N AI EM TE EH AKE

Management’s Discussion and Analysis > 31 The current scope of the Southern Access expansion between Superior and Flanagan, Illinois also consists of two phases. The initial phase, announced in May 2012, includes a planned increase in capacity from 400,000 bpd to 560,000 bpd at an estimated capital cost of approximately US$0.2 billion. In December 2012, EEP announced a further expansion of the Southern Access line between Superior and Flanagan, to increase capacity from 560,000 bpd to 1,200,000 bpd at an estimated capital cost of approximately US$1.3 billion. Both phases of the expansion would require only the addition of pumping horsepower and crude oil tanks at existing sites with no pipeline construction. Subject to finalization of scope and regulatory approvals, the target in-service date for the first phase of the expansion is expected to be in mid-2014. For the second phase of the expansion, which is also subject to finalization of design and regulatory approvals, the pump station expansion is expected to be available for service in 2015, with additional tankage requirements expected to be completed in 2016. As part the Light Oil Market Access Program, Enbridge and EEP announced the capacity expansion of the Lakehead System between Flanagan, Illinois and Griffith, Indiana. This section of the Lakehead System will be expanded by constructing a 122-kilometre (76-mile), 36-inch diameter twin of the existing Spearhead North Pipeline (Line 62). The project is expected to be completed at an estimated cost of approximately US$0.5 billion. The new line will have an initial capacity of 570,000 bpd and is expected to be placed into service in 2015. The projects collectively referred to as the Lakehead System Mainline Expansion are expected to cost approximately US$2.4 billion and will operate on a cost-of-service basis. The projects will be funded 60% by Enbridge and 40% by EEP under similar joint funding arrangement terms to those described under Growth Projects – Commercially Secured Projects – Sponsored Investments – Eastern Access. Furthermore, within one year of the final in service date, EEP will also have the option to increase its economic interest held at that time by up to 15%. SANDPIPER PROJECT In December 2012, Enbridge and EEP announced the Light Oil Market Access Program which consists of several individual projects. As part of this initiative, EEP plans to undertake the Sandpiper Project which will expand and extend EEP’s North Dakota feeder system. The Bakken takeaway capacity of the North Dakota System will be expanded by 225,000 bpd to a total of 580,000 bpd, with a target in-service date in 2016. The expansion will involve construction of an approximate 965-kilometre (600-mile) 24-inch diameter line from Beaver Lodge, North Dakota, to the Superior, Wisconsin, mainline system terminal. The new line will twin the 210,000 bpd North Dakota System mainline, which now terminates at Clearbrook Terminal in Minnesota, adding 225,000 bpd of capacity on the twin line between Beaver Lodge and Clearbrook, and 375,000 bpd of capacity between Clearbrook and Superior. The Sandpiper Project will be fully funded by EEP at an estimated capital cost of approximately US$2.5 billion. Subject to finalization of scope and regulatory approval, the capital cost will be rolled into the existing North Dakota System rate base, with the associated cost of service to be recovered in tolls. O P P P D R PR R ER A SA CT OJ AN PER T EC PI

CORPORATE MONTANA-ALBERTA TIE-LINE MATL is a 345-kilometre (215-mile) transmission line from Great Falls, Montana to Lethbridge, Alberta, designed to take advantage of the growing supply of electric power in Montana and buoyant power demand in Alberta. The total expected cost for both the first 300-MW phase of MATL and the expansion for an additional 300-MW has been increased to approximately US$0.4 billion, with expenditures to date of approximately US$0.3 billion. The permits required for construction had been previously obtained and in December 2012 the Alberta Utility Commission in Canada approved the Company’s updated design modifications. The system’s north-bound capacity, which is fully contracted, is now targeted to be in service in the second quarter of 2013, with the expansion targeted to be completed by the end of 2014. NEAL HOT SPRINGS GEOTHERMAL PROJECT The Company has partnered with U.S. Geothermal Inc. (U.S. Geothermal) to develop the 35-MW (22-MW, net) Neal Hot Springs Geothermal Project located in Malheur County, Oregon. U.S. Geothermal is constructing the plant and will operate the facility. The project declared commercial operation in November 2012, with the facility delivering electricity to the Idaho Power grid under a 25-year PPA. Enbridge invested approximately US$33 million for a 41% interest in the project. Growth Projects – Other Projects Under Development The following projects are also currently under development by the Company, but have not yet met Enbridge’s criteria to be classified as commercially secured. LIQUIDS PIPELINES WOODLAND PIPELINE EXTENSION In September 2012, Enbridge received approval from the Alberta Energy Resources Conservation Board (ERCB) to construct the Woodland Pipeline Extension Project. The project will extend the Woodland Pipeline south from Enbridge’s Cheecham Terminal to its Edmonton Terminal. The extension is a proposed 385-kilometre (228-mile), 36-inch diameter pipeline, requiring an investment of approximately $1.0 billion to $1.4 billion for an initial capacity of 400,000 bpd, expandable to 800,000 bpd. The estimated investment remains subject to finalization of scope and a definitive cost estimate. All major environmental approvals have been received and, subject to final commercial approval, Enbridge anticipates a 2015 in-service date. Project expenditures to date are approximately $0.1 billion, with pre-development costs being backstopped by shippers pending final commercial approval. Canada Corporate 40 Montana-Alberta Tie-Line United States Lethbridge Great Falls 40 32 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 33 TRUNKLINE JOINT VENTURE In February 2013, Enbridge entered into an agreement with Energy Transfer Partners L.P. (Energy Transfer) on the terms for joint development of a project to provide access to the eastern Gulf Coast refinery market from the Patoka, Illinois hub. Subject to FERC approval, the project will involve the conversion from natural gas service of certain segments of pipeline that are currently in operation as part of the natural gas system of Trunkline Gas Company, LLC, a wholly owned subsidiary of Energy Transfer and Energy Transfer Equity, L.P. The converted pipeline is expected to have a capacity of up to 420,000 to 660,000 bpd, depending on crude slate and the level of subscriptions received in an open season, and is expected to be in service by early 2015. Enbridge and Energy Transfer would each own a 50% interest in the venture. Enbridge’s participation in the venture is subject to a minimum level of commitments being obtained in the open season and on completion of due diligence on the conversion cost. Depending on the level of commitments and finalization of scope and capital cost estimates, Enbridge expects to invest approximately US$1.2 billion to US$1.7 billion. NORTHERN GATEWAY PROJECT Northern Gateway involves constructing a twin 1,177-kilometre (731-mile) pipeline system from near Edmonton, Alberta to a new marine terminal in Kitimat, British Columbia. One pipeline would transport crude oil for export from the Edmonton area to Kitimat and is proposed to be a 36-inch diameter line with an initial capacity of 525,000 bpd. The other pipeline would be used to import condensate and is proposed to be a 20-inch diameter line with an initial capacity of 193,000 bpd. Northern Gateway submitted an application to the NEB in May 2010. The Joint Review Panel (JRP) established to review the proposed project, pursuant to the NEB Act and the Canadian Environmental Assessment Act, has a broad mandate to assess the potential environmental effects of the project and to determine if it is in the public interest. Following sessions with the public, including Aboriginal groups, and the provision of additional information by Northern Gateway, the JRP issued a Hearing Order in May 2011 outlining the procedures to be followed. In August 2011, Northern Gateway filed commercial agreements with the NEB which provide for committed longterm service and capacity on both the proposed crude oil export and condensate import pipelines. Capacity has also been reserved for use by uncommitted shippers. In the fall of 2011, Northern Gateway responded to written questions by intervenors and government participants. In a Procedural Direction issued in December 2011, the JRP indicated community hearings would be scheduled so the Panel would hear all oral evidence from registered intervenors first, followed by oral statements from registered participants. Community hearings for oral evidence and statements took place between January and August 2012 in various communities. A written record of what was said each day in the community hearings is available on the Panel’s website. Intervenors responded to questions by Northern Gateway on July 6, 2012. Northern Gateway filed reply evidence to the evidence of the intervenors on July 20, 2012. The reply evidence contained details of further enhancements in pipeline design and operations. These extra measures, estimated to cost an additional $400 million to $500 million, together with additional marine infrastructure, result in a total estimated project cost of approximately $6.6 billion. The enhancements include: increasing pipeline wall thickness of the oil pipeline; additional pipeline wall thickness for water crossings such as major tributaries to the Fraser, Skeena and Kitimat Rivers; increasing the number of remotely-operated isolation valves by 50% within British Columbia to protect high-value fish habitat; increasing frequency of in-line inspection surveys across the entire Northern Gateway pipeline system by a minimum of 50% over and above current standards; installing dual leak detection systems; and staffing pump stations in remote locations on a 24 hour/7 day basis for on-site monitoring, heightened security and rapid response to abnormal conditions. The final hearings commenced on September 4, 2012 where Northern Gateway, intervenors, government participants and the JRP questioned those who have presented oral or written evidence.

The final hearings and the remaining oral statements from interested parties who do not reside along the pipeline corridor or shipping routes are expected to be completed by May 2013. Based on this projected schedule, the JRP expects to issue its reports and findings on the proposed project by December 2013. Of the 45 Aboriginal groups eligible to participate as equity owners, 26 have signed up to do so. Subject to continued commercial support, regulatory and other approvals, and adequately addressing landowner and local community concerns (including those of Aboriginal communities), the Company currently estimates that Northern Gateway could be in service in 2018 at the earliest. On February 23, 2012, Transport Canada published its TERMPOL Review Process Report of the Northern Gateway’s proposed marine operations. Transport Canada has filed the results of the study with the federal JRP tasked with assessing the project. The study reviewed the marine operations associated with the Northern Gateway terminal and associated tanker traffic in Canadian waters. The review concluded that: “While there will always be residual risk in any project, after reviewing the proponent’s studies and taking into account the proponent’s commitments, no regulatory concerns have been identified for the vessels, vessel operations, the proposed routes, navigability, other waterway users and the marine terminal operations associated with vessels supporting the Northern Gateway.” The TERMPOL report was prepared and approved by Canadian government authorities including Transport Canada; Environment Canada; Fisheries and Oceans Canada; Canadian Coast Guard; and Pacific Pilotage Authority Canada. The Gitxaala First Nations (Gitxaala) filed a Notice of Judicial Review with the Federal Court of Canada challenging the TERMPOL process on the grounds that there had not been adequate consultation with the Gitxaala with respect to the potential impacts on its Rights and Title resulting from the routine operation of the tankers servicing the Northern Gateway terminal in Kitimat. Following the hearing, the Federal Court of Canada issued a decision rejecting the Gitxaala challenge. Expenditures to date, which relate primarily to the regulatory process, are approximately $0.3 billion, of which approximately half is being funded by potential shippers on Northern Gateway. Given the many uncertainties surrounding the Northern Gateway, including final ownership structure, the potential financial impact of the project cannot be determined at this time. The JRP posts public filings related to Northern Gateway on its website at http://gatewaypanel.review-examen.gc.ca/ clf-nsi/hm-eng.html and Enbridge also maintains a Northern Gateway website in addition to information available on www.enbridge.com. The full regulatory application submitted to the NEB and the 2010 Enbridge Northern Gateway Community Social Responsibility Report are available on www.northerngateway.ca. None of the information contained on, or connected to, the JRP website, the Northern Gateway website or Enbridge’s website is incorporated in or otherwise part of this MD&A. GAS PIPELINES, PROCESSING AND ENERGY SERVICES NEXUS GAS TRANSMISSION PROJECT In September 2012, Enbridge, DTE Energy Company (DTE) and Spectra Energy Corp (Spectra) announced the execution of a Memorandum of Understanding to jointly develop the NEXUS Gas Transmission System (NEXUS), a project that will move growing supplies of Ohio Utica shale gas to markets in the United States midwest, including Ohio and Michigan and Ontario, Canada. The proposed NEXUS project will originate in northeastern Ohio, include approximately 400 kilometres (250 miles) of large diameter pipe, and be capable of transporting one bcf/d of natural gas. The line will follow existing utility corridors to an interconnect in Michigan and utilize the existing Vector pipeline to reach the Ontario market. Upon completion, Spectra would become a 20% owner in Vector, a joint venture between DTE and Enbridge. The next steps include analyzing open season service requests from the October 2012 open season and working with potential customers to formalize these requests into binding contract commitments. The targeted in-service date is late 2016. 34 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 35 Liquids Pipelines EARNINGS 2012 2011 2010 (millions of Canadian dollars) Canadian Mainline 432 336 326 Regional Oil Sands System 110 111 73 Southern Lights Pipeline 71 75 82 Seaway Pipeline 24 (3) – Spearhead Pipeline 37 17 29 Feeder Pipelines and Other 10 – 1 Adjusted earnings 684 536 511 Canadian Mainline – Line 9 tolling adjustment 6 10 – Canadian Mainline – changes in unrealized derivative fair value gains/(loss) 42 (48) – Canadian Mainline – shipper dispute settlement – 14 – Regional Oil Sands System – prior period adjustment (6) – – Regional Oil Sands System – asset impairment write-off – (8) – Regional Oil Sands System – gain on acquisition – – 20 Spearhead Pipeline – changes in unrealized derivative fair value gains – 1 – Earnings attributable to common shareholders 726 505 531 Liquids Pipelines adjusted earnings were $684 million in 2012 compared with adjusted earnings of $536 million in 2011 and $511 million in 2010. The Company continued to realize earnings growth on the Canadian Mainline in 2011 and 2012, primarily due to strong volume throughput and favourable operating performance under the CTS which took effective July 1, 2011. Other factors which contributed to the adjusted earnings increase included earnings from Seaway Pipeline since the initial reversal in May 2012, increased volumes on Spearhead Pipeline, as well as increased earnings from a number of the Company’s feeder pipelines. Liquids Pipelines earnings were impacted by the following adjusting items: Canadian Mainline earnings for 2012 and 2011 included Line 9 tolling adjustments related to services provided in prior periods. Canadian Mainline earnings for 2012 and 2011 reflected changes in unrealized fair value gains and losses on derivative financial instruments used to risk manage exposures inherent within the CTS, namely foreign exchange, power cost variability and allowance oil commodity prices. Canadian Mainline earnings for 2011 included $14 million from the settlement of a shipper dispute related to oil measurement adjustments in prior years. Regional Oil Sands System earnings for 2012 included a revenue recognition adjustment related to prior periods. Regional Oil Sands System earnings for 2011 included the write-off of development expenditures on certain project assets. Regional Oil Sands System earnings for 2010 included a gain on step-acquisition of crude oil storage assets. Spearhead Pipeline earnings for 2011 included changes in unrealized fair value gains on derivative financial instruments used to manage exposures to allowance oil commodity prices. LIQUIDS PIPELINES EARNINGS (millions of Canadian dollars) 1 Financial information has been extracted from financial statements prepared in accordance with U.S. GAAP. 2 Financial information has been extracted from financial statements prepared in accordance with Canadian GAAP. 332 454 511 536 684 328 2 445 2 531 1 505 1 726 1 12 11 10 09 08 GAAP Earnings Adjusted Earnings

CANADIAN MAINLINE The mainline system is comprised of Canadian Mainline and Lakehead System (the portion of the mainline in the United States that is operated by Enbridge and owned by EEP). Enbridge has operated, and frequently expanded, the mainline system since 1949. Through six adjacent pipelines, with a combined capacity of approximately 2.5 million bpd, which cross the Canada/United States border near Gretna, Manitoba and Neche, North Dakota, the system transports various grades of crude oil and diluted bitumen from western Canada to the midwest region of the United States and eastern Canada. Also included within the Canadian Mainline and located in eastern Canada are two crude oil pipelines and one refined products pipeline with a combined capacity of 0.4 million bpd. COMPETITIVE TOLL SETTLEMENT Canadian Mainline tolls are governed by the 10-year settlement reached between Enbridge and shippers on its mainline system and approved by the NEB in 2011. The CTS, which took effect on July 1, 2011, covers local tolls to be charged for service on the mainline system (with the exception of Lines 8 and 9). Under the terms of the CTS, the initial Canadian Local Toll (CLT), applicable to deliveries within western Canada, was based on the 2011 Incentive Tolling Settlement (ITS) toll and will be subsequently adjusted by 75% of the Canada Gross Domestic Product at Market Price Index, effective July 1, for each of the remaining nine years of the settlement. The CTS also provides for an International Joint Tariff (IJT) for crude oil shipments originating in Canada on the mainline system and delivered in the United States off the Lakehead System, and into eastern Canada. The IJT, which is based on a fixed toll for the term of the settlement that was negotiated between Enbridge and shippers, will be adjusted annually by the same factor as the CLT. In limited circumstances the shippers or Enbridge may elect to renegotiate the toll. If a renegotiation of the toll is triggered, Enbridge and the shippers will meet and use reasonable efforts to agree on how the CTS can be amended to accommodate the event. Local tolls for service on the Lakehead System will not be affected by the CTS and will continue to be established by EEP’s existing toll agreements. Under the terms of the IJT agreement between Enbridge and EEP, the Company’s share of the IJT toll relating to pipeline transportation of a batch from any western Canada receipt point to the United States border is equal to the IJT toll applicable to that batch’s United States delivery point less the Lakehead System’s local toll to that delivery point. This amount is referred to as the Canadian Mainline IJT Residual Toll. The IJT is designed to provide mainline shippers with a stable and competitive long-term toll, preserving and enhancing throughput on both the Canadian Mainline and Lakehead System. Earnings under the CTS are subject to variability in volume throughput, as well as capital and operating costs, and the United States dollar exchange rate. The Company may utilize derivative financial instruments to hedge foreign exchange rate risk on United States dollar denominated revenues and commodity price risk resulting from exposure to crude oil and power prices. LIQUIDS PIPELINES Zama Toronto Toledo Blaine Salt Lake City Portland Patoka Chicago Montreal Hardisty Fort McMurray Edmonton Cushing Gretna Casper Buffalo Enbridge System Chicap Pipeline Spearhead Pipeline Seaway Crude Pipeline System Frontier Pipeline NW System Waupisoo Pipeline Athabasca System Olympic Pipeline Mustang Pipeline 36 < ENBRIDGE INC. 2012 FINANCIAL REPORT i e n la em tla so s up te M Fo is p a W u i m on onr rd Bl re M To o ro r oro n on a Ca Bu o lo s as asp sp spe Sar k ak a Sa Sarnia ia a ag C e le e pe k li o to Pa Pat at C shi hi

Management’s Discussion and Analysis > 37 INCENTIVE TOLLING Prior to the CTS taking effect on July 1, 2011, tolls on Canadian Mainline were governed by various agreements which were subject to NEB approval. These agreements included both the 2011 and 2010 ITS applicable to the Canadian Mainline (excluding Lines 8 and 9), the Terrace agreement, the SEP II Risk Sharing agreement, the Alberta Clipper agreement and the Southern Access Expansion agreement which were recovered via the Mainline Expansion Toll. RESULTS OF OPERATIONS Canadian Mainline adjusted earnings were $432 million for the year ended December 31, 2012 compared with $336 million for the year ended December 31, 2011 and $326 million for the year ended December 31, 2010. The comparability of Canadian Mainline earnings year-over-year is affected by the change in tolling methodology. As noted previously, from July 1, 2011 onward, Canadian Mainline earnings (excluding Lines 8 and 9) were governed by the CTS, whereas operations for the first six months of 2011 and for the year ended December 31, 2010 were governed by a series of agreements, the most significant being the ITS applicable to the mainline system and the Terrace and Alberta Clipper agreements. Under the CTS, earnings are subject to variability in volume throughput and operating costs compared with prior tolling arrangements which were based on a cost-of-service methodology. Canadian Mainline revenues for the year ended December 31, 2012 reflected increased volumes and a higher Canadian Mainline IJT Residual Benchmark Toll which, under the IJT, is impacted by changes in the Lakehead System Local Toll. Volume throughput in 2012 was impacted by market conditions as incremental oil sands crude production in Alberta and strong production growth out of the Bakken in North Dakota bolstered supply to midwest markets and placed increased downward pressure on crude oil prices in that market. This discounted crude oil, coupled with strong refining margins, increased demand in the midwest for Canadian and Bakken crude oil supply and drove increased long haul barrels on Canadian Mainline and EEP’s Lakehead System. However, during the fourth quarter of 2012, Canadian Mainline was not able to capture the full throughput benefit of the increased supply available to it due to capacity limitations which arose from pressure restrictions being applied to certain lines pending completion of inspection and repair programs. The Company expects that capacity limitations will continue to constrain throughput during the first quarter of 2013 and, to a diminishing extent, for the remainder of 2013. An increase in operating and administrative costs, primarily due to higher employee related costs and higher leak remediation costs, also impacted 2012 adjusted earnings. CANADIAN MAINLINE— AVERAGE DELIVERIES (thousands of barrels per day) 1,522 1,562 1,537 1,554 1,646 12 11 10 09 08

Supplemental information on Canadian Mainline adjusted earnings for the year ended December 31, 2012 and for the six month period from July 1, the effective date of the CTS, to December 31, 2011 is as follows: Year ended December 31, Six months ended December 31, 2012 2012 2011 (millions of Canadian dollars) Revenues 1,367 711 618 Expenses Operating and administrative 382 192 194 Power 112 57 54 Depreciation and amortization 219 110 104 713 359 352 654 352 266 Other income/(expense) (4) (1) 5 Interest expense (131) (66) (66) 519 285 205 Income taxes (87) (48) (31) Adjusted earnings 432 237 174 Effective United States to Canadian dollar exchange rate 1 0.971 0.974 0.972 December 31, 2012 2011 IJT Benchmark Toll 2 (United States dollars per barrel) $ 3.94 $ 3.85 Lakehead System Local Toll 3 (United States dollars per barrel) $ 1.85 $ 2.01 Canadian Mainline IJT Residual Benchmark Toll 4 (United States dollars per barrel) $ 2.09 $ 1.84 1 Inclusive of realized gains or losses on foreign exchange derivative financial instruments. 2 The IJT Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Chicago, Illinois. A separate distance adjusted toll applies to shipments originating at receipt points other than Hardisty and lighter hydrocarbon liquids pay a lower toll than heavy crude oil. Effective July 1, 2012, the IJT benchmark toll increased from US$3.85 to US$3.94. 3 The Lakehead System Local Toll is per barrel of heavy crude oil transported from Neche, North Dakota to Chicago, Illinois. Effective April 1, 2012, this toll decreased from US$2.01 to US$1.76 and, effective July 1, 2012, this toll increased from US$1.76 to US$1.85. 4 The Canadian Mainline IJT Residual Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Gretna, Manitoba. Effective April 1, 2012, this toll increased from US$1.84 to US$2.09, with no change effective July 1, 2012. For any shipment, this toll is the difference between the IJT toll for that shipment and the Lakehead System Local Toll for that shipment. THROUGHPUT VOLUME 1 2012 2011 Q1 Q2 Q3 Q4 Total Q1 Q2 Q3 Q4 Total 1,687 1,659 1,617 1,622 1,646 1,602 1,457 1,565 1,594 1,554 1 Throughput volume, presented in thousand barrels per day, represents mainline deliveries ex-Gretna, Manitoba which is made up of United States and eastern Canada deliveries from western Canada. 38 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 39 Canadian Mainline revenues include the portion of the system covered by the CTS as well as revenues from Lines 8 and 9 in eastern Canada. Lines 8 and 9 are currently tolled on a separate basis and comprise a relatively small proportion of total Canadian Mainline revenues. CTS revenues include transportation revenues, the largest component, as well as allowance oil and revenues from receipt and delivery charges. Transportation revenues include revenues for volumes delivered off the Canadian Mainline at Gretna and on to the Lakehead System, to which Canadian Mainline IJT residual tolls apply, and revenues for volumes delivered to other western Canada delivery points, to which the CLT applies. Despite the many factors which affect Canadian Mainline revenues, the primary determinants of those revenues will be throughput volume ex-Gretna, the United States dollar Canadian Mainline IJT Residual Benchmark Toll and the effective foreign exchange rate at which resultant revenues are converted into Canadian dollars. The Company currently utilizes derivative financial instruments to hedge foreign exchange rate risk on United States dollar denominated revenues. The exact relationship between the primary determinants and actual Canadian Mainline revenues will vary somewhat from quarter to quarter but is expected to be relatively stable on average for a year, absent a systematic shift in receipt and delivery point mix or in crude oil type mix. The largest components of operating and administrative expense are employee related costs, pipeline integrity, repairs and maintenance, rents and leases and property taxes. Operating and administrative costs are relatively insensitive to throughput volumes. The primary drivers of future increases in operating costs are expected to be normal escalation in wage rates, prices for purchased services, the addition of new facilities and more extensive integrity and maintenance programs. Power, the most significant variable operating cost, is subject to variations in operating conditions, including system configuration, pumping patterns and pressure requirements; however, the primary determinants of this cost are the power prices in various jurisdictions and throughput volume. The relationship of power consumption to throughput volume is expected to be roughly proportional over a moderate range of volumes. The Company currently utilizes derivative financial instruments to hedge power prices. Depreciation and amortization expense will adjust over time as a result of additions to property, plant and equipment due to new facilities, including integrity capital expenditures. Canadian Mainline income taxes reflect current income taxes only. Under the CTS, the Company retains the ability to recover deferred income taxes under an NEB order governing flow-through income tax treatment and, as such, an offsetting regulatory asset related to deferred income taxes is recognized as incurred. The preceding financial overview includes expectations regarding future events and operating conditions that the Company believes are reasonable based on currently available information; however, such statements are not guarantees of future performance and are subject to change. Prior to the implementation of the CTS, revenues on the Canadian Mainline was recognized in a manner consistent with the underlying agreements as approved by the regulator, in accordance with rate-regulated accounting. The Company discontinued the application of rate-regulated accounting to its Canadian Mainline (excluding Lines 8 and 9) on a prospective basis commencing July 1, 2011. A regulatory asset of approximately $470 million related to deferred income taxes recorded at the date of discontinuance continued to be recognized as the Company retains the ability to recover deferred income taxes under an NEB order governing flow-through income tax treatment. The regulatory asset balance at the date of discontinuance related to tolling deferrals recognized in prior periods is being recovered through a surcharge to the CLT and IJT.

REGIONAL OIL SANDS SYSTEM Regional Oil Sands System consists of two long haul pipelines, the Athabasca Pipeline and the Waupisoo Pipeline, as well as the recently completed lateral pipeline and the receipt Wood Buffalo Pipeline. Regional Oil Sands System also includes a variety of other facilities such as the MacKay River, Christina Lake, Surmont and Long Lake facilities, as well as the Woodland Pipeline. It also includes two large terminals: the Athabasca Terminal located north of Fort McMurray, Alberta and the Cheecham Terminal, located 95 kilometres (59 miles) south of Fort McMurray where the Waupisoo Pipeline initiates. The Athabasca Pipeline is a 540-kilometre (335-mile) synthetic and heavy oil pipeline, built in 1999, which links the Athabasca oil sands in the Fort McMurray, Alberta region to a pipeline hub at Hardisty, Alberta. The Athabasca Pipeline has an ultimate design capacity of approximately 570,000 bpd, dependent on the viscosity of crude being shipped. It is currently configured to transport approximately 345,000 bpd. The Company has a long-term (30-year) take-or-pay contract with the major shipper on the Athabasca Pipeline which commenced in 1999. Revenues are recorded based on the contract terms negotiated with the major shipper, rather than the cash tolls collected. The Waupisoo Pipeline is a 380-kilometre (236-mile) synthetic and heavy oil pipeline that entered service in 2008 and provides access to the Edmonton market for oil sands producers. The Waupisoo Pipeline initiates at Enbridge’s Cheecham Terminal and terminates at its Edmonton Mainline Terminal. The pipeline had an initial design capacity, dependent on crude slate, of up to 350,000 bpd. The pipeline capacity was expanded to 415,000 bpd in the fourth quarter of 2012 and can ultimately be expanded to 600,000 bpd. Enbridge has a long-term (25-year) take-or-pay commitment with multiple shippers on the Waupisoo Pipeline who collectively have contracted for approximately three-quarters of the capacity. Prior to December 10, 2012 Regional Oil Sands System included the Hardisty Storage Caverns which included four salt caverns totaling 3.1 million barrels of storage capacity. The capacity at the facility is fully subscribed under longterm contracts that generate revenues from storage and terminaling fees. Along with the Hardisty Contract Terminals, the Hardisty Storage Caverns were transferred to the Fund in December 2012. See Sponsored Investments – Enbridge Income Fund – Crude Oil Storage and Renewable Energy Transfers for details of the transfer. RESULTS OF OPERATIONS Adjusted earnings for the year ended December 31, 2012 were $110 million compared with $111 million for the year ended December 31, 2011. Higher shipped volumes and increased tolls on certain laterals, and higher earnings from an annual escalation in storage and terminaling fees were more than offset by higher operating and administrative expense, and higher depreciation expense. Adjusted earnings for 2012 also included contributions from new regional infrastructure, the Woodland and Wood Buffalo pipelines, placed into service in the fourth quarter, although offset by earnings no longer being generated on assets sold to the Fund in December. REGIONAL OIL SANDS SYSTEM Waupisoo Pipeline Woodland Pipeline Athabasca System Wood Buffalo Pipeline Hardisty Fort McMurray Cheecham Edmonton Calgary Kerrobert 40 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 41 Adjusted earnings increased from $73 million for the year ended December 31, 2010 to $111 million for the year ended December 31, 2011. This increase in adjusted earnings reflected higher shipped volumes and increased tolls, as well as the continued positive impact of terminal infrastructure additions. Adjusted earnings for 2011 also included the impact of lower depreciation expense due to extended estimated useful lives of certain assets reflecting increased probable reservoir supply and commercial viability. ELK POINT PUMP STATION FACILITY OIL RELEASE On June 19, 2012, Enbridge reported an oil release at its Elk Point pumping station on Line 19 (Athabasca Pipeline), approximately 70 kilometres (44 miles) south of Bonnyville, Alberta and approximately 24 kilometres (15 miles) from the town of Elk Point, Alberta. On June 24, 2012, the Company restarted the Elk Point pumping station after completing necessary repairs. The contaminated soil and free product has been removed from the site for processing and disposal. On-going environmental testing and monitoring of the site is being conducted. Estimated volume of the release is approximately 1,400 barrels which were largely contained within the station. SOUTHERN LIGHTS PIPELINE The 180,000 bpd, 20-inch diameter Southern Lights Pipeline was placed into service on July 1, 2010 transporting diluent from Chicago, Illinois to Edmonton, Alberta. Enbridge receives tariff revenues under long-term (15-year) contracts with committed shippers. Tariffs provide for recovery of all operating and debt financing costs plus a return on equity (ROE) of 10%. Uncommitted volumes, up to a specified amount, generate tariff revenues that are fully credited to all shippers. Enbridge retains 25% of uncommitted tariff revenues on volumes above the specified amount, with the remainder being credited to shippers. Both the Canadian and United States uncommitted rates on Southern Lights Pipeline for 2010, 2011 and 2012 were challenged by certain shippers. The Canadian Southern Lights toll hearing was held before NEB panel members in November 2011. On February 9, 2012, the NEB issued its decision rejecting the challenge from uncommitted shippers and stating that tolls in place were just and reasonable, and more recently approved the 2010, 2011 and 2012 interim tolls as final. A FERC hearing was held in January 2012. Briefs were filed on February 27, 2012 and March 28, 2012 and an initial decision was issued on June 5, 2012. The initial decision found that the uncommitted rates were just and reasonable. The parties have filed briefs in response to this decision and the case is awaiting a final decision from the FERC. RESULTS OF OPERATIONS Southern Lights earnings decreased to $71 million for the year ended December 31, 2012 compared with $75 million for the year ended December 31, 2011 due to higher income tax expense which exceeded the deemed tax recovery in rates. For the year ended December 31, 2010, earnings of $82 million included leasing income from a pipeline until it was transferred to the mainline system effective May 1, 2010. REGIONAL OIL SANDS SYSTEM— AVERAGE DELIVERIES (thousands of barrels per day) 202 259 291 334 414 12 11 10 09 08

SEAWAY PIPELINE In 2011, Enbridge acquired a 50% interest in the 1,078-kilometre (670-mile) Seaway Pipeline including the 805-kilometre (500-mile), 30-inch diameter long-haul system from Freeport, Texas to Cushing, Oklahoma, as well as the Texas City Terminal and Distribution System which serves refineries in the Houston and Texas City areas. The Seaway Pipeline also includes 6.8 million barrels of crude oil tankage on the Texas Gulf Coast. The reversal of the Seaway Pipeline, enabling it to transport crude oil from the oversupplied hub in Cushing, Oklahoma to the Gulf Coast, was completed in May 2012, providing initial capacity of 150,000 bpd. In January 2013, further pump station additions and modifications were completed, increasing capacity available to shippers to up to 400,000 bpd, depending on crude slate. Actual throughput experienced to date in 2013 has been curtailed due to constraints on third party takeaway facilities. A lateral from the Seaway Jones Creek tankage to the ECHO crude oil terminal in Houston, Texas should eliminate these constraints when it comes into service, expected in the fourth quarter of 2013. Tolls are based on the contract terms agreed upon with shippers during the open seasons. Seaway Pipeline filed for market-based rates in December 2011. As the FERC had not issued a ruling on this application, Seaway Pipeline filed for initial rates in order to have rates in effect by the in-service date. The uncommitted rate on the Seaway Pipeline has been challenged by several shippers. A FERC hearing has been scheduled for March 2013. RESULTS OF OPERATIONS Seaway Pipeline earnings for the year ended December 31, 2012 of $24 million reflected preliminary service at an approximate capacity of 150,000 bpd which commenced in May 2012. Subsequent to year end, in January 2013, with further pump station additions and modifications, the reversal was completed, increasing to its intended capacity of 400,000 bpd. The $3 million loss recognized for the year ended December 31, 2011 was related to early stage business development costs that were not eligible for capitalization. SPEARHEAD PIPELINE Spearhead Pipeline delivers crude oil from the Flanagan, Illinois delivery point of the Lakehead System to Cushing, Oklahoma. The pipeline was originally placed into service in March 2006 and the Spearhead Pipeline Expansion was completed in May 2009, increasing capacity from 125,000 bpd to 193,300 bpd. Initial committed shippers and expansion shippers currently account for more than 70% of the 193,300 bpd capacity on Spearhead. Both the initial committed shippers and expansion shippers were required to enter into 10-year shipping commitments at negotiated rates that were offered during the open season process. The balance of the capacity is currently available to uncommitted shippers on a spot basis at FERC approved rates. RESULTS OF OPERATIONS Spearhead Pipeline adjusted earnings were $37 million for the year ended December 31, 2012 compared with $17 million for the year ended December 31, 2011. Spearhead Pipeline adjusted earnings increased as a result of higher volumes and tolls, partially offset by higher operating and administrative costs, including power and repairs and maintenance. Volumes significantly increased over 2011 due to higher commodity price differentials which increased demand at Cushing, Oklahoma in anticipation of additional capacity on the Seaway Pipeline for further transportation to the Gulf Coast. SPEARHEAD PIPELINE— AVERAGE DELIVERIES (thousands of barrels per day) 110 121 144 82 151 12 11 10 09 08 42 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 43 Spearhead Pipeline adjusted earnings were $17 million for the year ended December 31, 2011 compared with $29 million for the year ended December 31, 2010. The decrease in Spearhead Pipeline adjusted earnings primarily reflected lower throughput volumes as a result of market pricing dynamics at the time which weakened demand at Cushing, partially offset by the recognition of make-up rights which expired in the period. FEEDER PIPELINES AND OTHER Feeder Pipelines and Other primarily includes the Company’s 85% interest in Olympic Pipe Line Company (Olympic), the largest refined products pipeline in the State of Washington, transporting approximately 290,000 bpd of gasoline, diesel and jet fuel. It also includes the NW System, which transports crude oil from Norman Wells in the Northwest Territories to Zama, Alberta; interests in a number of liquids pipelines in the United States; and business development costs related to Liquids Pipelines activities. Prior to December 10, 2012, Feeder Pipelines and Other also included the Hardisty Contract Terminals, which is comprised of 19 tanks with a working capacity of approximately 7.5 million barrels of storage capacity. Along with the Hardisty Storage Caverns, the Hardisty Contract Terminals were transferred to the Fund in December 2012. See Sponsored Investments – Enbridge Income Fund – Crude Oil Storage and Renewable Energy Transfers for details of the transfer. RESULTS OF OPERATIONS In 2012, Feeder Pipelines and Other earnings were $10 million compared with nil for the year ended December 31, 2011 and earnings of $1 million in 2010. The increase in earnings was primarily a result of a higher contribution from Olympic due to a tariff increase, higher volumes on Toledo Pipeline and increased terminaling fees. In 2011, earnings from Toledo Pipeline were negatively impacted by integrity work on Lines 6A and 6B of EEP’s Lakehead System. The decrease in earnings from 2010 to 2011 reflected higher business development costs. BUSINESS RISKS The risks identified below are specific to the Liquids Pipelines business. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks. SUPPLY AND DEMAND The profitability of the Company’s liquids pipelines depends to some extent on the volume of products transported on its pipeline systems. The volume of shipments depends primarily on the supply of, and demand for, crude oil and other liquid hydrocarbons from western Canada. Investment levels and related development activities by crude oil producers in conventional and oil sands production directly impacts the level of supply from the WCSB. Investment levels are influenced by crude oil producers’ expectations of crude oil prices, future operating costs, United States demand and availability of markets for produced crude oil. Demand depends, among other things, on weather, gasoline price and consumption, manufacturing levels, alternative energy sources and global supply disruptions. Crude oil prices have been and are expected to be sustained at levels that will incent continued development of oil sands and conventional exploration and drilling, increasing production, and creating increased demand for new pipeline infrastructure to access markets both in North America and abroad.

VOLUME RISK A decrease in volumes transported by certain of the Company’s liquids pipelines, including the Company’s mainline system and the base Lakehead System owned by EEP, can directly and adversely affect revenues and earnings. Shippers are not required to enter into long-term shipping commitments on Enbridge’s Canadian Mainline; rather, monthly volume nominations are accepted. A decline in volumes transported can be influenced by factors beyond the Company’s control, including competition, regulatory action, weather, storage levels, alternative energy sources, decreased demand, fluctuations in commodity prices, economic conditions, supply disruptions, availability of supply connected to the systems and adequacy of infrastructure to move supply into and out of the systems. This risk is partially mitigated by the CTS agreement, which allows Enbridge to negotiate an amendment to the agreement in the event certain minimum threshold volumes are not met. MARKET PRICE RISK The CTS agreement for the Canadian Mainline exposes the Company to risks related to movements in foreign exchange rates, interest rates and commodity prices, particularly power prices. Foreign exchange risk arises as the Company’s IJT under the CTS is charged in United States dollars. These risks have been substantially managed through the Company’s hedging program by using financial contracts to fix the prices of United States dollars, commodities and interest rates. Certain of these financial contracts do not qualify for cash flow hedge accounting and, therefore, the Company’s earnings are exposed to associated changes in the mark-to-market value of these contracts. COMPETITION Competition among existing pipelines is based primarily on the cost of transportation, access to supply, the quality and reliability of service, contract carrier alternatives and proximity to markets. Other competing carriers are available to ship western Canadian liquids hydrocarbons to markets in either Canada or the United States. Competition also arises from existing and proposed pipelines that provide, or are proposed to provide, access to market areas currently served by the Company’s liquids pipelines. One such competing project serves markets at Wood River, Illinois and Cushing, Oklahoma. This pipeline has a capacity of 590,000 bpd, and could connect to a proposed 700,000 bpd pipeline serving Gulf Coast refineries, which is expected to be in-service in late 2013. Commercial support has also been announced for the construction of additional ex-Alberta capacity of 830,000 bpd to Steele City, Nebraska, with an expected in-service date of 2015, to further supply WCSB crude to the Gulf Coast. Additionally, due to deep discounting of WCSB commodities compared with WTI pricing and the relatively long lead-times required to build new pipeline capacity, transportation of crude oil by rail is gaining favour with shippers seeking flexibility in accessing current markets. While pricing differentials remain high, shipper support for pipeline expansion out of the WCSB could be tempered. However, the Company believes that its liquids pipelines continue to provide attractive options to producers in the WCSB due to its competitive tolls and multiple delivery and storage points. Enbridge’s current complement of growth projects to expand market access are also expected to provide shippers long-term competitive solutions for oil transport. The Company’s existing right-of-way for the Canadian Mainline also provides a competitive advantage as it can be difficult and costly to obtain rights of way for new pipelines traversing new areas. POTENTIAL PRESSURE RESTRICTIONS The Company’s liquids systems consist of individual pipelines of varying ages. With appropriate inspection and maintenance, the physical life of a pipeline is indefinitely long; however, as pipelines age the level of expenditures required for inspection and maintenance may increase. Pressure restrictions may from time to time be established on the Company’s pipelines. Pressure restrictions reduce the available capacity of the applicable line segment and could result in a loss of throughput if and when the full capacity of that line segment would otherwise have been utilized. Certain of the Company’s liquids pipelines, including the Company’s Canadian Mainline, could be adversely affected by pressure restrictions that reduce volumes transported. Temporary pressure restrictions have been established on some sections of certain pipelines pending completion of specific inspection and repair programs, and had the effect of limiting throughput during the fourth quarter of 2012. 44 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 45 REGULATION The Canadian Mainline and other liquids pipelines are subject to the actions of various regulators, including the NEB. Actions of the regulators related to tariffs, tolls and facilities impact earnings from those operations. The Company believes that regulatory risk is reduced through the negotiation of long-term agreements with shippers, such as the CTS, which govern the majority of the segment’s assets. Gas Distribution EARNINGS 2012 2011 2010 (millions of Canadian dollars) Enbridge Gas Distribution Inc. (EGD) 149 135 132 Other Gas Distribution and Storage 27 38 30 Adjusted earnings 176 173 162 EGD – (warmer)/colder than normal weather (23) 1 (12) EGD – tax rate changes (9) – – EGD – recognition of regulatory asset 63 – – Other Gas Distribution and Storage – regulatory deferral write-off – (262) – Earnings/(loss) attributable to common shareholders 207 (88) 150 Adjusted earnings from Gas Distribution were $176 million for the year ended December 31, 2012 compared with $173 million for 2011 and $162 million for the year ended December 31, 2010. The increase in Gas Distribution’s adjusted earnings over these years primarily resulted from customer growth and favourable performance by EGD under its Incentive Regulation (IR) arrangement. In 2012, adjusted earnings were negatively impacted by changes in rate setting methodology applicable to gas distribution operations in New Brunswick. Gas Distribution earnings were impacted by the following adjusting items: EGD earnings were adjusted to reflect the impact of weather. Earnings from EGD for 2012 reflected the impact of unfavourable tax rate changes on deferred income tax liabilities. EGD earnings for 2012 included the recognition of a regulatory asset related to recovery of OPEB costs pursuant to an OEB rate order. See Gas Distribution – Enbridge Gas Distribution Inc. – 2013 Rate Application. Other Gas Distribution and Storage earnings for 2011 reflected the discontinuation of rate-regulated accounting for EGNB and the related write-off of a deferred regulatory asset and certain capitalized operating costs, net of tax. See Gas Distribution – Other Gas Distribution and Storage – Enbridge Gas New Brunswick Inc. – Regulatory Matters. GAS DISTRIBUTION EARNINGS (millions of Canadian dollars) 1 Financial information has been extracted from financial statements prepared in accordance with U.S. GAAP. 2 Financial information has been extracted from financial statements prepared in accordance with Canadian GAAP. 141 154 162 173 176 161 2 186 2 150 1 (88) 1 207 1 12 11 10 09 08 GAAP Earnings Adjusted Earnings

ENBRIDGE GAS DISTRIBUTION INC. EGD is Canada’s largest natural gas distribution company and has been in operation for more than 160 years. It serves approximately two million customers in central and eastern Ontario and parts of northern New York State. EGD’s utility operations are regulated by the OEB and by the New York State Public Service Commission. INCENTIVE REGULATION In 2007, the Company filed a rate application requesting a revenue cap incentive rate mechanism calculated on a revenue per customer basis with the OEB for the 2008 to 2012 period. The OEB approved the settlement agreement with customer representatives and the Company moved to an IR methodology, which remained in effect through 2012. The objectives of the settlement agreement were as follows: reduce regulatory costs; provide incentives for improved efficiency; provide more flexibility for utility management; and provide more stable rates to customers. Under the settlement agreement, the Company was allowed to earn and fully retain 100 basis points (bps) over the base return. Any return over 100 bps was required to be shared with customers on an equal basis. The earnings sharing mechanism resulted in the return of revenue to customers of $10 million for the year ended December 31, 2012 (2011 – $13 million; 2010 – $19 million). 2013 RATE APPLICATION In January 2012, the Company filed an application with the OEB to set rates for 2013 on a cost of service basis and on October 3, 2012 the Company filed with the OEB a settlement agreement reached with its interveners relating to the Company’s 2013 rate application. The settlement agreement was approved by the OEB on November 2, 2012, which resolved all elements of the rate application except a requested change in deemed equity supporting the rate base which was heard by the OEB in November 2012. In its final decision issued on February 7, 2013, the OEB denied the Company’s requested increase in the deemed equity level. The settlement agreement approved in November 2012 also established the right to recover an existing OPEB liability of approximately $89 million ($63 million after-tax). The amount will be collected in rates over a 20-year time period commencing in 2013. The rate order further provided for future OPEB and pension costs, determined on an accrual basis, to be recovered in rates. ENBRIDGE GAS DISTRIBUTION– NUMBER OF ACTIVE CUSTOMERS (thousands) 1,898 1,937 1,981 1,997 2,032 12 11 10 09 08 46 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 47 RESULTS OF OPERATIONS Adjusted earnings for the year ended December 31, 2012 were $149 million compared with $135 million for the year ended December 31, 2011. The increase in EGD’s adjusted earnings was primarily due to customer growth, favourable rate variances and higher pipeline capacity optimization. This growth was partially offset by an increase in system integrity and safety-related costs and higher employee costs, as well as higher depreciation due to a higher in-service asset base. Adjusted earnings for the year ended December 31, 2011 were $135 million compared with $132 million for the year ended December 31, 2010. The increase in EGD’s adjusted earnings was primarily due to customer growth, lower interest expense and lower taxes. These positive impacts were partially offset by higher customer support costs, as well as an increase in system integrity and employee related expenses. Depreciation expense also increjased due to a higher overall asset base. OTHER GAS DISTRIBUTION AND STORAGE Other Gas Distribution includes natural gas distribution utility operations in Quebec and New Brunswick, the most significant being EGNB (100% owned and operated by the Company), which owns the natural gas distribution franchise in the province of New Brunswick. EGNB has approximately 11,000 customers and is regulated by the New Brunswick Energy and Utilities Board (EUB). ENBRIDGE GAS NEW BRUNSWICK INC. – REGULATORY MATTERS On December 9, 2011 the Government of New Brunswick tabled and then subsequently passed legislation related to the regulatory process for setting rates for gas distribution within the province. The legislation permitted the government to implement new regulations which could affect the franchise agreement between EGNB and the province, impact prior decisions by the province’s independent regulator and influence the regulator’s future decisions. However, significant details of the rate setting process were left to be established in the new regulations and, as such, the effect of such legislation was not determinable at that time. A final rates and tariffs regulation was subsequently enacted by the Government of New Brunswick on April 16, 2012. Based on the amended rate setting methodology and specific conditions outlined therein, EGNB no longer met the criteria for the continuation of rate-regulated accounting. As a result, the Company eliminated from its Consolidated Statements of Financial Position a deferred regulatory asset of $180 million and a regulatory asset with respect to capitalized operating costs of $103 million, net of an income tax recovery of $21 million. As the final rates and tariffs regulation published on April 16, 2012 provided further evidence of a condition that existed on December 31, 2011, the charge totaling $262 million, after tax, was reflected as a subsequent event in the Company’s Consolidated Financial Statements for the year ended December 31, 2011 presented in accordance with U.S. GAAP and filed in May 2012. The charge reflected Management’s best estimate based on facts available at the time and may be subject to further revision based on future actions or interpretations of the regulator, the Government of New Brunswick or other factors, including legal proceedings which Enbridge has commenced. GAS DISTRIBUTION Enbridge Gas New Brunswick Enbridge Gas Distribution Toronto Chicago Montreal Quebec City Ottawa Moncton n on o to on n ct o cton ton nc ge dge G e dg To Toro t o ro ront D i i is o t n r g d b rid id s a u t i i o

On April 26, 2012, the Company, Enbridge Energy Distribution Inc. (EEDI) and EGNB commenced an action against the Province of New Brunswick in the New Brunswick Court of Queen’s Bench, claiming damages in the amount of $650 million as a result of the continuing breaches by the province of the General Franchise Agreement it signed with Enbridge in 1999. Additionally, on May 2, 2012, the Company, EEDI and EGNB filed a Notice of Application with the New Brunswick Court of Queen’s Bench seeking a declaration from the Court that the rates and tariffs regulation is invalid. In a decision released on August 23, 2012, the Court dismissed EGNB’s Application. EGNB has filed a Notice of Appeal with the New Brunswick Court of Appeal and a hearing of the appeal is expected to be held during the first quarter of 2013. On September 20, 2012, the EUB issued a decision regarding EGNB’s rates that were to take effect as of October 1, 2012. The EUB’s decision applies the rate-setting methodology set out in the rates and tariffs regulation. EGNB has filed an application for judicial review of the EUB’s rate order with the New Brunswick Court of Appeal, which is expected to hear the application during the first half of 2013, sometime after the hearing of the appeal of the August 2012 New Brunswick Court of Queen’s Bench decision discussed above. There is no assurance these actions will be successful or will result in any recovery. RESULTS OF OPERATIONS Other Gas Distribution and Storage adjusted earnings were $27 million for the year ended December 31, 2012 compared with $38 million for the year ended December 31, 2011. This adjusted earnings decrease was primarily due to the change in rate setting methodology applicable to EGNB enacted in 2012. Effective January 1, 2012, the discontinuance of rate-regulated accounting at EGNB resulted in earnings subject to increased variability, including quarterly seasonality, as there was no further accumulation of the regulatory deferral account. Earnings for 2012 were impacted by lower volume due to a decrease in demand for natural gas, which was the result of a warmer than normal winter. Adjusted earnings for the year ended December 31, 2011 were $38 million compared with $30 million for the year ended December 31, 2010, primarily due to an increased contribution from Enbridge’s Ontario unregulated gas storage business. BUSINESS RISKS The risks identified below are specific to Gas Distribution business. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks. REGULATION The utility operations of Gas Distribution are regulated by the OEB and EUB among others. Regulators’ future actions may differ from current expectations, or future legislative changes may impact the regulatory environment in which Gas Distribution operates. To the extent that the regulators’ future actions are different from current expectations, the timing and amount of recovery or refund of amounts recorded on the Consolidated Statements of Financial Position, or that would have been recorded on the Consolidated Statements of Financial Position in absence of the effects of regulation, could be different from the amounts that are eventually recovered or refunded. In 2012, EGD operated under the IR Framework which permitted it to recover, with OEB approval, certain costs that were beyond management control, but that were necessary for the maintenance of its services. The IR Framework also included a mechanism to reassess the IR plan and return to cost of service if there were significant and unanticipated developments that threaten the sustainability of the IR plan. The above noted terms set out in the settlement agreement mitigated the Company’s risk to factors beyond management’s control. Commencing in 2013, EGD’s rates will be established on a cost of service basis, under which EGD will be entitled to recover costs of providing its service and to earn a specified ROE. Rate relief may be sought for significant amounts that were not forecasted; however, to the extent the OEB denies recovery of such costs, the Company’s earnings may be impacted. 48 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 49 In 2012, the Government of New Brunswick enacted a final rates and tariffs regulation amending the rate setting methodology applicable to EGNB, resulting in a write-off of certain regulatory balances totaling $262 million, net of tax, reflected as a subsequent event in the Consolidated Statements of Earnings for the year ended December 31, 2011. The Company commenced actions against the Province of New Brunswick; however, there is no assurance these actions will be successful or will result in any recovery. NATURAL GAS COST RISK EGD does not profit from the sale of natural gas nor is it at risk for the difference between the actual cost of natural gas purchased and the price approved by the OEB. This difference is deferred as a receivable from or payable to customers until the OEB approves its refund or collection. EGD monitors the balance and its potential impact on customers and may request interim rate relief to recover or refund the natural gas cost differential. While the cost of natural gas does not impact EGD’s earnings, it does affect the amount of EGD’s investment in gas in storage. EGNB is also subject to natural gas cost risk as increases in natural gas prices that cannot be charged to customers could negatively impact earnings. VOLUME RISK Since customers are billed on a volumetric basis, EGD’s ability to collect its total revenue requirement (the cost of providing service) depends on achieving the forecast distribution volume established in the rate-making process. The probability of realizing such volume is contingent upon four key forecast variables: weather, economic conditions, pricing of competitive energy sources and growth in the number of customers. Weather is a significant driver of delivery volumes, given that a significant portion of EGD’s customer base uses natural gas for space heating. Distribution volume may also be impacted by the increased adoption of energy efficient technologies, along with more efficient building construction, that continues to place downward pressure on consumption. In addition, conservation efforts by customers may further contribute to a decline in annual average consumption. Sales and transportation of gas for customers in the residential and small commercial sectors account for approximately 80% of total distribution volume. Sales and transportation service to large volume commercial and industrial customers is more susceptible to prevailing economic conditions. As well, the pricing of competitive energy sources affects volume distributed to these sectors as some customers have the ability to switch to an alternate fuel. Customer additions from all market sectors are important as continued expansion adds to the total consumption of natural gas. Even in those circumstances where EGD attains its total forecast distribution volume, it may not earn its expected ROE due to other forecast variables such as the mix between the higher margin residential and commercial sectors and the lower margin industrial sector. EGNB is also subject to volume risk as the impact of weather conditions on demand for natural gas could result in earnings fluctuations.

Gas Pipelines, Processing and Energy Services EARNINGS 2012 2011 2010 (millions of Canadian dollars) Aux Sable 68 55 37 Energy Services 40 56 21 Alliance Pipeline US 24 26 25 Vector Pipeline 16 18 15 Enbridge Offshore Pipelines (Offshore) (3) (7) 23 Other 9 15 2 Adjusted earnings 154 163 123 Aux Sable – changes in unrealized derivative fair value gains/(loss) 10 (7) 7 Energy Services – changes in unrealized derivative fair value gains/(loss) (537) 125 (8) Energy Services – credit recovery – – 1 Offshore – asset impairment loss (105) – – Offshore – property insurance recoveries from hurricanes – – 2 Other – changes in unrealized derivative fair value gains – 24 – Earnings/(loss) attributable to common shareholders (478) 305 125 Adjusted earnings from Gas Pipelines, Processing and Energy Services were $154 million for the year ended December 31, 2012 compared with $163 million for the year ended December 31, 2011 and $123 million for the year ended December 31, 2010. Notable trends over these years included favourable performance from Aux Sable, due to higher realized fractionation margins and new assets placed into service, and continued weakness in the Company’s Offshore operations. The variability in earnings year-over-year attributable to Energy Services is due to changing market conditions which give rise to greater or fewer margin opportunities. Gas Pipelines, Processing and Energy Services earnings were impacted by the following adjusting items: Aux Sable earnings for each period reflected changes in the fair value of unrealized derivative financial instruments related to the Company’s forward gas processing risk management position. Energy Services earnings for each period reflected changes in unrealized fair value gains and losses related to the revaluation of financial derivatives used to manage the profitability of transportation and storage transactions. A gain or loss on such a financial derivative corresponds to a similar but opposite loss or gain on the value of the underlying physical transaction which is expected to be realized in the future when the physical transaction settles. Unlike the change in the value of the financial derivative, the loss or gain on the value of the underlying physical transaction is not recorded for financial statement purposes until the periods in which it is realized. GAS PIPELINES, PROCESSING AND ENERGY SERVICES EARNINGS (millions of Canadian dollars) 1 Financial information has been extracted from financial statements prepared in accordance with U.S. GAAP. 2 Financial information has been extracted from financial statements prepared in accordance with Canadian GAAP. 141 116 123 163 154 767 2 428 2 125 1 305 1 (478) 1 12 11 10 09 08 GAAP Earnings Adjusted Earnings 50 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 51 Energy Services earnings for 2010 included partial recoveries from the sale of its receivable from Lehman Brothers. Offshore earnings for 2012 were impacted by an asset impairment loss related to certain of its assets, predominantly located within the Stingray and Garden Banks corridors. See Gas Pipelines, Processing and Energy Services – Enbridge Offshore Pipelines – Asset Impairment for further details. Offshore earnings for 2010 included insurance proceeds related to the replacement of damaged infrastructure as a result of a 2008 hurricane. Other earnings for 2011 reflected changes in the fair value of unrealized derivative financial instruments. AUX SABLE Enbridge owns 42.7% of Aux Sable, a NGL extraction and fractionation business, which owns and operates a plant near Chicago, Illinois at the terminus of Alliance. The plant extracts NGL from the liquids-rich natural gas transported on Alliance, as necessary to meet gas quality specifications of downstream transmission and distribution companies and to take advantage of positive fractionation spreads. Aux Sable sells its NGL production to a single counterparty under a long-term contract. Aux Sable receives a fixed annual fee and a share of any net margin generated from the business in excess of specified natural gas processing margin thresholds (the upside sharing mechanism). In addition, Aux Sable is compensated for all operating, maintenance and capital costs associated with its facilities subject to certain limits on capital costs. The counterparty supplies, at its cost, all make-up gas and fuel gas requirements of the Aux Sable plant and pays market rates for the capacity on Alliance held by an Aux Sable affiliate. The contract is for an initial term of 20 years, expiring March 31, 2026, and may be extended by mutual agreement for 10-year terms. Aux Sable also owns and operates facilities upstream of Alliance that deliver liquids-rich gas volumes into the pipeline for further processing at the Aux Sable plant. These facilities include the Prairie Rose Pipeline and the Palermo Conditioning Plant in the Bakken area of North Dakota and the Septimus Gas Plant and the Septimus Pipeline in the Montney area of British Columbia. Aux Sable has contracted capacity of the Septimus Pipeline and the Septimus Gas Plant to a producer under a 10-year take-or-pay contract which provides for a return on and of invested capital. Actual operating costs are recovered from the producer. Additional revenues are earned by Aux Sable based on a sharing of NGL margin available. In 2012, 80% of the capacity in the Palermo Gas Plant and the Prairie Rose Pipeline was contracted to producers under take-or-pay contracts. Several producers’ contract commitments decline over the next few years while certain producer contract commitments continue through 2020 under 10-year take or pay contracts or with life-of-lease reserve dedication. RESULTS OF OPERATIONS Aux Sable adjusted earnings were $68 million for the year ended December 31, 2012 compared with $55 million for the year ended December 31, 2011 and $37 million for the year ended December 31, 2010. Adjusted earnings increased primarily due to higher realized fractionation margins and earnings contributions from the Prairie Rose Pipeline and the Palermo Conditioning Plant acquired in July 2011. BUSINESS RISKS The risks identified below are specific to Aux Sable. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks. COMMODITY PRICE RISK Aux Sable’s margin earned through the upside sharing mechanism is subject to commodity price risk arising from movements in natural gas and NGL prices and differentials. These risks may be mitigated through the Company’s risk management activities. S O O C M P D R PR CE R SK C RIS RIC Y TY IT M

VOLUME RISK A decrease in gas volumes or a decrease in the NGL content of the gas stream delivered by Alliance to the Aux Sable plant can directly and adversely affect the margin earned through the upside sharing mechanism. Alliance is well positioned to deliver incremental liquids-rich gas production from new developments in the Montney and Bakken regions, thereby mitigating volume risk. In addition, Aux Sable attracts liquids-rich gas to Alliance through inducement and rich gas premium contracts with producers. ENERGY SERVICES Energy Services provides energy supply and marketing services to North American refiners, producers and other customers. Crude oil and NGL marketing services are provided by Tidal Energy. This business transacts at many North American market hubs and provides its customers with various services, including transportation, storage, supply management, hedging programs and product exchanges. Tidal Energy is primarily a physical barrel marketing company focused on capturing value from quality, time and location differentials when opportunities arise. To execute these strategies, Energy Services may lease storage or rail cars, as well as hold nomination or contractual rights on both third party and Enbridge-owned pipelines and storage facilities. Any commodity price exposure created from this physical business is closely monitored and must comply with the Company’s formal risk management policies. Tidal Energy also provides natural gas marketing services, including marketing natural gas to optimize commitments on certain natural gas pipelines. To the extent transportation costs exceed the basis (location) differential, earnings will be negatively affected. Tidal Energy also provides natural gas supply, transportation, balancing and storage for third parties, leveraging its natural gas marketing expertise and access to transportation capacity. RESULTS OF OPERATIONS Energy Services adjusted earnings decreased from $56 million for the year ended December 31, 2011 to $40 million for the year ended December 31, 2012. The decline was primarily due to changing market conditions which gave rise to fewer margin opportunities in crude oil and NGL marketing. Energy Services adjusted earnings were $56 million for the year ended December 31, 2011 compared with $21 million for the year ended December 31, 2010. This increase was primarily attributable to crude oil marketing strategies designed to capture basis (location) differentials and tank management revenue when opportunities arise. Partially offsetting positive earnings contributions from crude oil services were declines in natural gas marketing due to narrower natural gas basis (location) spreads, which impact the Company’s merchant capacity on certain natural gas pipelines. Earnings from Energy Services are dependent on market conditions, including, but not limited to, quality, time and location differentials, and may not be indicative of results to be achieved in future periods. BUSINESS RISKS The risks identified below are specific to Energy Services. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks. COMMODITY PRICE RISK Energy Services generates margin by capitalizing on quality, time and location differentials when opportunities arise. Volatility in commodity prices and changing marketing conditions could limit margin opportunities. Furthermore, commodity prices could have negative earnings impacts if the cost of the commodity is greater than resell prices achieved by the Company. Energy Services activities are conducted in compliance with and under the oversight of the Company’s formal risk management policies. 52 < ENBRIDGE INC. 2012 FINANCIAL REPORT O VO S R E SK LU RIS M L O C OD PR R CE SK C S RIS RIC Y TY IT M M

Management’s Discussion and Analysis > 53 ALLIANCE PIPELINE US Alliance, which includes both the Canadian and United States portions of the pipeline system, consists of an approximately 3,000-kilometre (1,864-mile) integrated, high-pressure natural gas transmission pipeline system and an approximately 730-kilometre (454-mile) lateral pipeline system and related infrastructure. Alliance transports liquids-rich natural gas from northeast British Columbia, northwest Alberta and the Bakken area in North Dakota to Channahon, Illinois. Alliance Pipeline US and Alliance Pipeline Canada have firm service shipping contract capacity to deliver 1.405 bcf/d and 1.325 bcf/d, respectively. Enbridge owns 50% of Alliance Pipeline US, while the Fund, described under Sponsored Investments, owns 50% of Alliance Pipeline Canada. Alliance connects with Aux Sable (of which Enbridge owns 42.7%), a NGL extraction and fractionation facility in Channahon, Illinois. The natural gas may then be transported to two local natural gas distribution systems in the Chicago area and five interstate natural gas pipelines, providing shippers with access to natural gas markets in the midwestern and northeastern United States and eastern Canada. Alliance Pipeline US is adjacent to the Bakken oil formation in North Dakota which offers new incremental sources of liquids-rich natural gas for delivery to downstream markets. In February 2010, a new receipt point on the pipeline near Towner, North Dakota was placed into service. The receipt point connects to the Prairie Rose Pipeline, which initially provided access to a shipper operating out of the Bakken formation with a firm transportation contract for an initial contract capacity of 40 mmcf/d under a 10-year contract. An additional 40 mmcf/d of firm transportation capacity at this same receipt point became effective February 2011. The Prairie Rose Pipeline was acquired by Aux Sable in 2011. TRANSPORTATION CONTRACTS Alliance Pipeline US has long-term, take-or-pay contracts to transport substantially all its 1.405 bcf/d of natural gas capacity, with terms ending on December 1, 2015. A small percentage of natural gas is being contracted on a short-term basis with an annual renewal option. These contracts permit Alliance Pipeline US, whose operations are regulated by the FERC, to recover the cost of service, which includes operating and maintenance costs, the cost of financing, an allowance for income tax, an annual allowance for depreciation and an allowed ROE of 10.9%. RESULTS OF OPERATIONS Alliance Pipeline US earnings of $24 million for the year ended December 31, 2012 were comparable with earnings of $26 million and $25 million for the years ended December 31, 2011 and 2010, respectively, reflecting its stable, cost-of-service commercial construct. ALLIANCE PIPELINE US—AVERAGE THROUGHPUT VOLUMES (millions of cubic feet per day) 1,609 1,601 1,600 1,564 1,553 12 11 10 09 08

VECTOR PIPELINE Vector, which includes both the Canadian and United States portions of the pipeline system, consists of 560 kilometres (348 miles) of mainline natural gas transmission pipeline between the Chicago, Illinois hub and the storage complex at Dawn, Ontario. Vector’s primary sources of supply are through interconnections with Alliance and the Northern Border Pipeline in Joliet, Illinois. Vector has the capacity to deliver a nominal 1.3 bcf/d and is operating at or near capacity. The Company provides operating services to and holds a 60% joint venture interest in Vector. TRANSPORTATION CONTRACTS The total long haul capacity of Vector is approximately 87% committed through November 2015. Approximately 55% of the long haul capacity is committed through firm negotiated rate transportation contracts with shippers and approved by the FERC, while the remaining committed capacity is sold at market rates. In December 2012, shippers under negotiated rate transportation contracts which represent 27% of the systems long haul capacity elected to extend their commitments beyond December 1, 2015 for one additional year and preserve the option to continue their commitments on an annual basis. The remaining 28% of negotiated rate transportation contract shippers elected not to extend their commitments beyond its original contract term of November 2015. Vector is entitled to additional compensation from shippers that elected not to extend their contracts beyond 2015. Transportation service is provided through a number of different forms of service agreements such as Firm Transportation Service and Interruptible Transportation Service. Vector is an interstate natural gas pipeline with FERC and NEB approved tariffs that establish the rates, terms and conditions governing its service to customers. On the United States portion of Vector, tariff rates are determined using a cost of service methodology and tariff changes may only be implemented upon approval by the FERC. For 2012, the FERC approved maximum tariff rates included an underlying weighted average after-tax ROE component of 11.2%. On the Canadian portion, Vector is required to file its negotiated tolls calculation with the NEB on an annual basis. Tolls are calculated on a levelized basis that include a rate of return incentive mechanism based on construction costs and are subject to a rate cap. In 2012, maximum tariff tolls include a ROE component of 10.5% after-tax. RESULTS OF OPERATIONS Vector earnings were $16 million for the year ended December 31, 2012 comparable with $18 million for the year ended December 31, 2011 and $15 million for the year ended December 31, 2010. BUSINESS RISKS The risks identified below are specific to both Alliance Pipeline US and Vector. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks. VECTOR PIPELINE—AVERAGE THROUGHPUT VOLUMES (millions of cubic feet per day) 1,321 1,334 1,456 1,525 1,534 12 11 10 09 08 54 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 55 SUPPLY AND DEMAND Currently, natural gas pipeline capacity out of the WCSB exceeds supply, due to the low price of natural gas and increased production from new shale gas discoveries. Alliance Pipeline US and Vector have been unaffected by this excess supply environment to date mainly because of long-term capacity contracts extending primarily to 2015. However, excess capacity out of the WCSB and depressed natural gas prices have led to a reduction or deferral of investment in upstream gas development, and could negatively impact re-contracting beyond this term. Re-contracting risk is mitigated to some extent as Alliance Pipeline US is well positioned to deliver incremental liquids-rich gas production from new developments in the Montney and Bakken regions. Alliance Pipeline US is also engaged with market participants in developing new receipt facilities and services to expand its reach in transporting liquids-rich gas to premium markets. In addition, Aux Sable, through its participation in midstream businesses upstream of Alliance Pipeline US, attracts liquids-rich gas to Alliance Pipeline US by offering incremental value for producers’ NGL. Vector’s interruptible capacity could be negatively impacted by the basis (location) differential in the price of natural gas between Chicago, Illinois and Dawn, Ontario relative to the transportation toll. COMPETITION Alliance Pipeline US faces competition for pipeline transportation services to the Chicago area from both existing and proposed pipeline projects. Competing pipelines provide natural gas transportation services from the WCSB and the Bakken to natural gas markets in the midwestern United States. In addition, there are several proposals to convert or upgrade existing pipelines or to build new pipelines to serve these markets. Any new or upgraded pipelines could either allow shippers greater access to natural gas markets or offer natural gas transportation services that are more desirable than those provided by Alliance Pipeline US because of location, facilities or other factors. In addition, these pipelines could charge rates or provide transportation services to locations that result in greater net profit for shippers, with the effect of forcing Alliance Pipeline US to realize lower revenues and cash flows. Shippers on Alliance Pipeline US currently have access to additional high compression delivery capacity at no additional cost, other than fuel requirements, serving to enhance the competitive position of Alliance Pipeline US. Vector faces competition for pipeline transportation services to its delivery points from new supply sources and traditional low cost pipelines, which could offer transportation that is more desirable to shippers because of cost, supply location, facilities or other factors. Vector has mitigated this risk by entering into long-term firm transportation contracts and the effectiveness of these contracts is evidenced by the increased utilization of the pipeline since its construction, despite the presence of transportation alternatives. Vector and Alliance pipelines also face potential competition from new sources of natural gas such as the Marcellus shale formation, which is among the largest gas plays in North America. The Marcellus shale formation is in close proximity to the Chicago Hub. The development of the Marcellus shale formation could provide an alternate source of gas to the Chicago Hub as well as decrease the northeastern region of the United States’ reliance on natural gas imports from Canada. NATURAL GAS PIPELINES Fort St. John Toronto Sarnia Superior Regina Chicago Edmonton Alliance Pipeline (US) Vector Pipeline Alliance Pipeline (Canada) Fo on Re ine p e e o To Tor or l i i i Sarn rn rnia ia n Sa r a

REGULATION Both the United States portion of Vector and Alliance Pipeline US operations are subject to regulation by the FERC. If tariff rates are protested, the timing and amount of recovery or refund of amounts recorded on the Consolidated Statements of Financial Position could be different from the amounts that are eventually recovered or refunded. In addition, future profitability of the entities could be negatively impacted. On a yearly basis, following consultation with shippers, Alliance Pipeline US files its annual rates with the FERC for approval. FERC has intensified its oversight of financial reporting, risk standards and affiliate rules and has issued new standards on managing gas pipeline integrity. The Company continues ongoing dialogue with regulatory agencies and participates in industry groups to ensure it is informed of emerging issues in a timely manner. ENBRIDGE OFFSHORE PIPELINES Offshore is comprised of 13 natural gas gathering and FERC-regulated transmission pipelines and one oil pipeline with a capacity of 60,000 bpd, in five major corridors in the Gulf of Mexico, extending to deepwater developments. These pipelines include almost 2,400 kilometres (1,500 miles) of underwater pipe and onshore facilities with total capacity of approximately 7.3 bcf/d. Offshore currently moves approximately 40% of offshore deepwater gas production through its systems in the Gulf of Mexico. TRANSPORTATION CONTRACTS The primary shippers on the Offshore systems are producers who execute life-of-lease commitments in connection with transmission and gathering service contracts. In exchange, Offshore provides firm capacity for the contract term at an agreed upon rate. The firm capacity made available generally reflects the lease’s maximum sustainable production. The transportation contracts allow the shippers to define a maximum daily quantity (MDQ), which corresponds with the expected production life. The contracts typically have minimum throughput volumes which are subject to take-or-pay criteria, but also provide the shippers with flexibility, subject to advance notice criteria, to modify the projected MDQ schedule to match current delivery expectations. The majority of long-term transport rates are market-based, with revenue generation directly tied to actual production deliveries. Some of the systems operate under a cost-of-service methodology while others have minimum take-or-pay obligations. The business model utilized on a go forward basis and included in the WRGGS, Big Foot, Venice and Heidelberg commercially secured projects differs from the historic model. These new projects have a base level return which is locked in through take or pay commitments. If volumes reach producer anticipated levels, the return on these projects may increase. In addition, Enbridge has minimal capital cost risk on these projects and commercial agreements continue to contain life-of-lease commitments. The WRGGS and Big Foot project agreements provide for recovery of actual capital costs to complete the project in fees payable by producers over the contract term. The Venice project provides for a capital cost risk sharing mechanism whereby Enbridge is exposed to a portion of the capital costs in excess of an agreed upon target. Conversely, Enbridge can recover in fees from producers a portion of the capital cost savings below the agreed upon target. Adjustment is allowed for many of the Heidelberg project variables affecting its cost, with Enbridge bearing the residual capital cost risk after these adjustments have been applied. ENBRIDGE OFFSHORE PIPELINES Houston New Orleans Dallas Gulf of Mexico 56 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 57 ASSET IMPAIRMENT In December 2012, the Company recorded an impairment charge of $166 million ($105 million after-tax) related to certain of its Offshore assets, predominantly located within the Stingray and Garden Banks corridors in the Gulf of Mexico. The Company had been pursuing alternative uses for these assets; however, due to changing competitive conditions in the fourth quarter of 2012, the Company concluded that such alternatives were no longer likely to proceed. In addition, unique to these assets is their significant reliance on natural gas production from shallow water areas in the Gulf of Mexico which have been challenged by macro-economic factors including prevalence of onshore shale gas production, hurricane disruptions, additional regulation and the low natural gas commodity price environment. RESULTS OF OPERATIONS For the year ended December 31, 2012, Offshore incurred an adjusted loss of $3 million compared with a loss of $7 million for the year ended December 31, 2011. Offshore realized a second year of consecutive losses due to weak volumes from delayed drilling programs and more scheduled production outages by producers in the Gulf of Mexico. The decrease in loss year-over-year resulted from a higher transportation rate for volumes shipped on the Stingray Pipeline System, a reduction in interest expense and a $2 million favourable impact related to the reversal of a shipper reserve pertaining to a rate case from 2011. For the year ended December 31, 2011, Offshore incurred a loss of $7 million compared with adjusted earnings of $23 million for the year ended December 31, 2010. The decrease in adjusted earnings reflected continued volume declines due to the slower regulatory permitting process and delayed drilling programs by producers. Increased operating and administrative costs, including higher insurance premiums and employee benefits as well as increased depreciation expense, also contributed to the decrease in earnings from the prior year. BUSINESS RISKS The risks identified below are specific to Offshore. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks. WEATHER Adverse weather, such as hurricanes, may impact Offshore’s financial performance directly or indirectly. Direct impacts may include damage to offshore facilities resulting in lower throughput, as well as inspection and repair costs. Indirect impacts may include damage to third party production platforms, onshore processing plants and pipelines that may decrease throughput on offshore systems. Offshore’s insurance policy includes specific coverage related to named windstorms (such as hurricanes), for all systems, but does not cover business interruption. The occurrence of hurricanes in the Gulf Coast increases the cost and availability of insurance coverage and Enbridge may not be able, or may choose not, to insure against this risk in the future. Enbridge facilities are engineered to withstand hurricane forces and constant monitoring of weather allows for timely evacuation of personnel and shutdown of facilities; however, damages to assets may still occur. ENBRIDGE OFFSHORE PIPELINES— AVERAGE THROUGHPUT VOLUMES (millions of cubic feet per day) 1,672 2,037 1,962 1,595 1,540 12 11 10 09 08 WE R ER ATH A EATHER WEA

COMPETITION There is competition for new and existing business in the Gulf of Mexico, with an increasing number of competitors willing to construct and operate production host platforms for future deepwater prospects. Offshore has been able to capture key opportunities, allowing it to more fully utilize existing capacity. Offshore’s gas pipelines serve a majority of the strategically located deepwater host platforms, positioning it favourably to make incremental investments for new platform connections and receive additional transportation volumes from sub-sea development of smaller fields tied back to existing host platforms. Offshore is also able to construct pipelines to transport crude oil, diversifying the risk of declining gas production, as demonstrated with the planned Big Foot Oil and Heidelberg pipelines. Given rates of decline, offshore pipelines typically have available capacity, resulting in significant competition for new developments in the Gulf of Mexico. Competing developments may impact the recoverability of the Company’s long-lived offshore assets. SUPPLY AND DEMAND Low natural gas prices, in part due to the prevalence of onshore shale gas, have resulted in reduced investment in exploration activities and producing infrastructure. Offshore diversifies its risk of declining gas production through the construction of crude oil pipelines as noted above. To date, crude oil prices have supported stable offshore investment; however, a future decline in crude oil prices could change the potential for future investment opportunities. Further, a sustained decline in either natural gas or crude oil commodity prices could impact the recoverability of long-lived offshore assets. In the fourth quarter of 2012, Offshore recognized an impairment charge of $105 million, net of tax, primarily related to shallow water natural gas assets, due to changing competitive conditions and sustained weakness in natural gas prices. REGULATION The transportation rates on many of Offshore’s transmission pipelines are generally based on a regulated cost of service methodology and are subject to regulation by the FERC. These rates are subject to challenge from time-to-time. The Macondo oil spill in 2010 has altered the offshore regulatory environment. Although the moratorium on deepwater drilling has been lifted, future deepwater drilling activity will be subject to heightened regulation and oversight. Increased regulation may impact the levels and timing of future exploration and drilling activity in the region and the resultant production volumes available to ship on the Offshore system. The shifting business environment could result in increases in available capacity, resulting in heightened competition. OTHER RISKS Other risks directly impacting financial performance include underperformance relative to expected reservoir production rates, delays in project start-up timing, changes in plans by shippers and capital expenditures in excess of those estimated. Capital risk is mitigated in some circumstances by having area producers as joint venture partners or through cost of service tolling arrangements or other pre-arranged terms in commercial agreements. Start-up delays are mitigated by the right to collect stand-by fees. 58 < ENBRIDGE INC. 2012 FINANCIAL REPORT O O PETI C N TIO TI TIT M U P PP P D D D A MA A S EM PLY AN EMA AN LY O R A LAT U N G L REG TIO ATI S OTH R R ER KS SKS RIS TH

Management’s Discussion and Analysis > 59 OTHER Other includes operating results from the Company’s investments in renewable energy projects and business development expenditures. WIND AND SOLAR RESOURCES TRANSFER In May 2012, the Company acquired from Renewable Energy Systems Canada Inc. the remaining 10% interest in the Greenwich Wind Energy Project (Greenwich) through Greenwich Windfarm, LP, for $27 million, increasing its ownership to 100%. On December 10, 2012, Greenwich, the Amherstburg Solar Project (Amherstburg) and the Tilbury Solar Project (Tilbury) were transferred to the Fund. See Sponsored Investments – Enbridge Income Fund – Crude Oil Storage and Renewable Energy Transfers for details of the transfer. In October 2011, ownership of the Ontario Wind, Sarnia Solar and Talbot Wind energy projects was transferred to the Fund with earnings contributions from these assets, net of noncontrolling interests, reflected within the Sponsored Investments segment effective October 21, 2011. RESULTS OF OPERATIONS Other adjusted earnings for the year ended December 31, 2012 were $9 million compared with $15 million for the year ended December 31, 2011. The decrease in adjusted earnings was primarily due to the sale of Ontario Wind, Sarnia Solar and Talbot Wind energy projects to the Fund in October 2011, followed by the sale of Greenwich, Amherstburg and Tilbury to the Fund in December 2012. Higher business development costs also contributed to the decrease in adjusted earnings. Partially offsetting this increase were the contributions from Cedar Point and Greenwich, which were commissioned in late 2011, and Silver State which was commissioned in early 2012. Other adjusted earnings increased from $2 million for the year ended December 31, 2010 to $15 million for the year ended December 31, 2011. This increase reflected strong contributions primarily from the Sarnia Solar expansion and Talbot Wind Energy Project, both of which were completed in the latter part of 2010. In addition, adjusted earnings for 2011 reflected several newly constructed green energy projects, including Cedar Point, Greenwich and Amherstburg. Sponsored Investments EARNINGS 2012 2011 2010 (millions of Canadian dollars) Enbridge Energy Partners, L.P. (EEP) 141 151 122 Enbridge Energy, Limited Partnership (EELP) – Alberta Clipper US 38 42 42 Enbridge Income Fund (the Fund) 84 51 42 Adjusted earnings 263 244 206 EEP – leak insurance recoveries 24 50 – EEP – leak remediation costs and lost revenue (9) (33) (106) EEP – changes in unrealized derivative fair value gains/(loss) (2) 3 (1) EEP – NGL trucking and marketing investigation costs (1) (3) – EEP – prior period adjustment 7 – – EEP – shipper dispute settlement – 8 – EEP – lawsuit settlement – 1 – EEP – impact of unusual weather conditions – (1) – EEP – Lakehead System billing correction – – 1 EEP – asset impairment loss – – (2) Earnings attributable to common shareholders 282 269 98

Adjusted earnings from Sponsored Investments were $263 million for the year ended December 31, 2012 compared with $244 million for the year ended December 31, 2011. The increase in adjusted earnings resulted primarily from increased contributions from the Fund following the transfer of certain renewable energy and crude oil storage assets from Enbridge and its wholly-owned subsidiaries in late 2012 and late 2011. Adjusted earnings from Sponsored Investments were $244 million for the year ended December 31, 2011 compared with $206 million in 2010. The increase in adjusted earnings resulted primarily from increased contributions from EEP as a result of positive operating factors, including growth projects, and contributions from renewable energy assets transferred to the Fund. Sponsored Investments earnings were impacted by the following adjusting items: Earnings from EEP for 2012 and 2011 included insurance recoveries associated with the Line 6B crude oil release. See Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases – Line 6B Crude Oil Release. Earnings from EEP for each period included a charge related to estimated costs, before insurance recoveries, associated with the Lines 6A, 6B and Line 14 crude oil releases. EEP earnings from 2010 also included a charge of $3 million (net to Enbridge) related to lost revenue as a result of the crude oil releases. See Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Line 14 Crude Oil Release and Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases. Earnings from EEP included changes in the unrealized fair value on derivative financial instruments in each period. EEP earnings for 2012 and 2011 reflected charges for legal and accounting costs associated with an investigation at a NGL trucking and marketing subsidiary, which was concluded in the first quarter of 2012. EEP earnings for 2012 reflected a non-recurring out-of-period adjustment. EEP earnings for 2011 included proceeds from the settlement of a shipper dispute related to oil measurement adjustments in prior years. EEP earnings for 2011 included proceeds related to the settlement of a lawsuit during the first quarter of 2011. EEP earnings for 2011 included an unfavourable effect related to decreased volumes due to uncharacteristically cold weather in February 2011 that disrupted normal operations of its natural gas systems. EEP earnings for 2010 included Lakehead System billing corrections. EEP earnings for 2010 included charges related to asset impairment losses. SPONSORED INVESTMENTS EARNINGS (millions of Canadian dollars) 1 Financial information has been extracted from financial statements prepared in accordance with U.S. GAAP. 2 Financial information has been extracted from financial statements prepared in accordance with Canadian GAAP. 101 151 206 244 263 111 2 141 2 98 1 269 1 282 1 12 11 10 09 08 GAAP Earnings Adjusted Earnings 60 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 61 ENBRIDGE ENERGY PARTNERS, L.P. EEP owns and operates crude oil and liquid petroleum transportation and storage assets and natural gas and NGL gathering, treating, processing, transportation and marketing assets in the United States. Significant assets include the Lakehead System, which is the extension of the Canadian Mainline in the United States, the Mid-Continent crude oil system consisting of an interstate crude oil pipeline and storage facilities, a crude oil gathering system and interstate pipeline system in North Dakota and natural gas assets located primarily in Texas. Subsidiaries of Enbridge provide services to EEP in connection with the operation of its liquids assets, including the Lakehead System. In September 2010, EEP acquired the entities that comprise the Elk City Natural Gas Gathering and Processing System (Elk City System) for US$686 million. The Elk City System extends from southwestern Oklahoma to Hemphill County in the Texas Panhandle and consists of approximately 1,290 kilometres (800 miles) of natural gas gathering and transportation pipelines, one carbon dioxide treating plant and three cryogenic processing plants with a total capacity of 370 mmcf/d and a combined NGL production capability of 20,000 bpd. The acquisition of the Elk City System complements EEP’s existing Anadarko natural gas system by providing additional processing capacity and expansion capability. OWNERSHIP INTEREST Enbridge’s ownership interest in EEP is impacted by EEP’s issuance and sale of its Class A common units. To the extent Enbridge does not fully participate in these offerings, the Company’s ownership interest in EEP is reduced. At December 31, 2012, Enbridge’s ownership interest in EEP was 21.8% (2011 – 23.0%; 2010 – 25.5%). The Company’s average ownership interest in EEP during 2012 was 23.0% (2011 – 24.4%; 2010 – 26.7%). DISTRIBUTIONS EEP makes quarterly distributions of its available cash to its common unitholders. Under the Partnership Agreement, Enbridge Energy Company, Inc. (EECI), a wholly owned subsidiary of Enbridge, as general partner (GP), receives incremental incentive cash distributions, which represent incentive income on the portion of cash distributions (on a per unit basis) that exceed certain target thresholds as follows: Unitholders including Enbridge GP Interest Quarterly cash distributions per unit: 1 Up to $0.295 per unit 98% 2% First target – $0.295 per unit up to $0.350 per unit 85% 15% Second target – $0.350 per unit up to $0.495 per unit 75% 25% Over second target – cash distributions greater than $0.495 per unit 50% 50% 1 Distributions restated to reflect EEP’s two-for-one stock split which was effective April 2011. In July 2012, EEP increased its quarterly distribution to $0.5435 per unit from $0.5325. Of the $141 million Enbridge recognized as adjusted earnings from EEP during 2012, $59 million (2011 – $46 million; 2010 – $33 million) were GP incentive earnings, while the remainder was Enbridge’s limited partner share of EEP’s earnings. ENBRIDGE ENERGY PARTNERS, L.P. Wood River Sarnia Toledo Superior Seattle Blaine Salt Lake City Regina Portland Patoka Chicago Minot Cushing Cromer Clearbrook Gretna Casper Houston New Orleans Calgary Dallas Lakehead System Natural Gas Assets North Dakota System Ozark Pipeline Enbridge Inc. Liquids Pipelines Gas Pipelines a ea s ns Po Bl B tl Bla la P al alg i a in C g re e l t and nd Cle le lea ea e l Cl k ok a o oo ar Mi i e pe o io er erior upe Su Sup rio Sa n a a Sarn r ia a La o T g To P ka R Wo Woo oo o r d od o Cu C s us u Cus h sh g ing ng n Da Dal al all ll N an ans Or w H e rl o Ho i P p g n d i nc n r n b d . g E P i i i ne e p q d ip u s s L i l i

RESULTS OF OPERATIONS Adjusted earnings from EEP were $141 million for the year ended December 31, 2012 compared with $151 million for the year ended December 31, 2011. Adjusted earnings from EEP for 2012 included higher GP incentive income and strong results from the liquids business primarily due to higher average delivery volumes and increased tolls on all major liquids systems, as well as contributions from storage terminal and other facilities that were placed into service during 2012. Earnings from the natural gas business decreased as a result of lower natural gas and NGL prices. Earnings were also negatively impacted by an increase in operating and administrative costs, specifically pipeline integrity costs, personnel costs and higher property taxes. EEP adjusted earnings increased from $122 million for the year ended December 31, 2010 to $151 million for the year ended December 31, 2011. The increase was primarily attributable to strong results from its natural gas business as a result of higher natural gas and NGL volumes, including those associated with the acquisition of the Elk City System in September 2010, as well as higher GP incentive income. Increased volumes in liquids pipelines and a full year contribution from Alberta Clipper also drove higher earnings in 2011. These positive factors were partially offset by an increase in operating and administrative costs and higher financing costs. LAKEHEAD SYSTEM LINE 14 CRUDE OIL RELEASE On July 27, 2012, a release of crude oil was detected on Line 14 of EEP’s Lakehead System near Grand Marsh, Wisconsin. The estimated volume of oil released was approximately 1,700 barrels. EEP received a Corrective Action Order (CAO) from the Pipeline and Hazardous Materials Safety Administration (PHMSA) on July 30, 2012, followed by an amended CAO on August 1, 2012. The CAOs required EEP to take certain corrective actions, some of which have already been completed and some are still ongoing, as part of an overall plan for its Lakehead System. A notable part of the CAOs was to hire an independent third party pipeline expert to review and assess EEP’s overall integrity program. An independent third party expert was contracted during the third quarter of 2012 and its work is currently ongoing. Upon restart of Line 14 on August 7, 2012, PHMSA restricted the operating pressure to 80% of the pressure in place at the time immediately prior to the incident. The pressure restrictions will remain in place until such time EEP can demonstrate that the root cause of the incident has been remediated. EEP has revised the disclosed estimate for repair and remediation related costs associated with this crude oil release as at December 31, 2012 to approximately US$10 million ($1 million after-tax attributable to Enbridge), inclusive of approximately US$2 million of lost revenue, and excluding any fines and penalties. Despite the efforts EEP has made to ensure the reasonableness of its estimate, changes to the estimated amounts associated with this release are possible as more reliable information becomes available. EEP will be pursuing claims under Enbridge’s comprehensive insurance policy, although it does not expect any recoveries to be significant. LAKEHEAD SYSTEM LINES 6A AND 6B CRUDE OIL RELEASES LINE CRUDE OIL RELEASE On July 26, 2010, a release of crude oil on Line 6B of EEP’s Lakehead System was reported near Marshall, Michigan. EEP estimates that approximately 20,000 barrels of crude oil were leaked at the site, a portion of which reached the Talmadge Creek, a waterway that feeds the Kalamazoo River. The released crude oil affected approximately 61 kilometres (38 miles) of shoreline along the Talmadge Creek and Kalamazoo River waterways, including residential areas, businesses, farmland and marshland between Marshall and downstream of Battle Creek, Michigan. In response to the release, a unified command structure was established under the jurisdiction of the Environmental Protection Agency (EPA), the Michigan Department of Natural Resources and Environment and other federal, state and local agencies. 62 < ENBRIDGE INC. 2012 FINANCIAL REPORT O C AS L B 6B D 6 E R R CR A EA U SE LEA EL REL L OI E N LI

Management’s Discussion and Analysis > 63 During the second quarter of 2012, local authorities allowed the Kalamazoo River and Morrow Lake, which were affected by the Line 6B crude oil release, to be re-opened for recreational use. EEP continues to perform necessary remediation, restoration and monitoring of the areas affected by the Line 6B crude oil release. EEP expects to make payments for additional costs associated with submerged oil and sheen monitoring and recovery operations, including reassessment, remediation and restoration of the area, air and groundwater monitoring, scientific studies and hydrodynamic modeling, along with legal, professional and regulatory costs through future periods. All of the initiatives EEP is undertaking in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities. On July 2, 2012, EEP received a Notice of Probable Violation (NOPV) from the PHMSA related to the July 26, 2010 Line 6B crude oil release, which resulted in payment of a US$3.7 million civil penalty in the third quarter of 2012. EEP included the amount of the penalty in its total estimated cost for the Line 6B crude oil release. In addition, on July 10, 2012 the National Transportation Safety Board presented the results of its investigation into the Line 6B crude oil release and subsequently publicly posted its final report on July 26, 2012. As at December 31, 2012, EEP revised the total incident cost accrual to US$820 million ($137 million after-tax attributable to Enbridge), primarily due to an estimate of extended oversight by regulators and additional legal costs associated with various lawsuits, which is an increase of US$55 million ($8 million after-tax attributable to Enbridge) from its estimate at December 31, 2011. This total estimate is before insurance recoveries and excludes additional fines and penalties, which may be imposed by federal, state and local government agencies, other than the PHMSA civil penalty described above. On October 3, 2012, EEP received a letter from the EPA regarding a Proposed Order for potential incremental containment and active recovery of submerged oil. EEP is in discussions with the EPA regarding the agency’s intent with respect to certain elements of the Proposed Order and the appropriate scope of these activities. The nature and scope of any additional remediation activities that regulators may require is currently uncertain. Studies and additional technical evaluation by EEP, the EPA and other regulatory agencies may need to be completed before a final determination of any additional remediation activities can be determined. EEP has accrued the estimated costs it deemed likely to be incurred. However, when a final determination of the appropriate nature and scope of any additional remediation is made, it could result in significant cost being accrued. Expected losses associated with the Line 6B crude oil release included those costs that were considered probable and that could be reasonably estimated at December 31, 2012. Despite the efforts EEP has made to ensure the reasonableness of its estimates, there continues to be the potential for EEP to incur additional costs in connection with this crude oil release due to variations in any or all of the cost categories, including modified or revised requirements from regulatory agencies, in addition to fines and penalties and expenditures associated with litigation and settlement of claims. LINE 6A CRUDE OIL RELEASE A release of crude oil from Line 6A of EEP’s Lakehead System was reported in an industrial area of Romeoville, Illinois on September 9, 2010. EEP estimates that approximately 9,000 barrels of crude oil were released, of which approximately 1,400 barrels were removed from the pipeline as part of the repair. Some of the released crude oil went onto a roadway, into a storm sewer, a waste water treatment facility and then into a nearby retention pond. All but a small amount of the crude oil was recovered. EEP completed excavation and replacement of the pipeline segment and returned it to service on September 17, 2010. The cause of the crude oil release remains subject to investigation by federal and state environmental and pipeline safety regulators. EEP continues to monitor the areas affected by the crude oil release from Line 6A of its Lakehead System near Romeoville, Illinois in September 2010 for any additional requirements; however, the cleanup, remediation and restoration of the areas affected by the release have been completed. AS O A EA D C R R CR E A U L SE LEA EL REL L OI E N LI

In connection with this crude oil release, the cost estimate as at December 31, 2012 remains at approximately US$48 million ($7 million after-tax attributable to Enbridge), before insurance recoveries and excluding fines and penalties. EEP has the potential of incurring additional costs in connection with this crude oil release, including fines and penalties as well as expenditures associated with litigation. EEP is pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained. INSURANCE RECOVERIES EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates which renews in May of each year. In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis based on an insurance allocation agreement EEP has entered into with Enbridge and one of Enbridge’s subsidiaries. The insurance program includes commercial liability insurance coverage that is consistent with coverage considered customary for its industry and includes coverage for environmental incidents such as those incurred for the crude oil releases from Lines 6A and 6B, excluding costs for fines and penalties. The claims for the crude oil release for Line 6B are covered by Enbridge’s comprehensive insurance policy that expired on April 30, 2011, which had an aggregate limit of US$650 million for pollution liability. Based on EEP’s remediation spending through December 31, 2012, Enbridge and its affiliates have exceeded the limits of their coverage under this insurance policy. Additionally, fines and penalties would not be covered under the existing insurance policy. For the years ended December 31, 2012 and 2011, EEP recognized US$170 million ($24 million after-tax attributable to Enbridge) and US$335 million ($50 million after-tax attributable to Enbridge), respectively, of insurance recoveries as reductions to Environmental costs in the Consolidated Statements of Earnings. As at December 31, 2012, EEP had recorded total insurance recoveries of US$505 million ($74 million after-tax attributable to Enbridge) for the Line 6B crude oil release and expects to recover the balance of the aggregate liability insurance coverage of US$145 million from its insurers in future periods. EEP will record receivables for additional amounts received through insurance recoveries during the period it deems recovery to be probable. Effective May 1, 2012, Enbridge renewed its comprehensive insurance program, through April 30, 2013, with a current liability aggregate limit of US$660 million, including sudden and accidental pollution liability. LEGAL AND REGULATORY PROCEEDINGS A number of United States governmental agencies and regulators have initiated investigations into the Line 6A and Line 6B crude oil releases. Approximately 30 actions or claims have been filed against Enbridge, EEP or their affiliates in United States federal and state courts in connection with the Line 6B crude oil release, including direct actions and actions seeking class status. Based on the current status of these cases, EEP does not expect the outcome of these actions to be material. As noted above, on July 2, 2012, PHMSA announced a NOPV related to the Line 6B crude oil release, including a civil penalty of US$3.7 million that EEP paid in the third quarter of 2012. One claim related to the Line 6A crude oil release has been filed against Enbridge, EEP or their affiliates by the State of Illinois in the Illinois state court. The parties are currently operating under an agreed interim order. 64 < ENBRIDGE INC. 2012 FINANCIAL REPORT OV S R RA ES VER REC R ER CE A C C U VERI ANC NS I O O D AL P D ED RY R AN R PR G G GA A LAT A A S C UL REG NG I EED CEE Y ATO LEG L

Management’s Discussion and Analysis > 65 ENBRIDGE ENERGY, LIMITED PARTNERSHIP – ALBERTA CLIPPER US In July 2009, the Company committed to fund 66.7% of the cost to construct the United States segment of the Alberta Clipper Project. The Company funded 66.7% of the project’s equity requirements through EELP, while 66.7% of the debt funding was made through EEP. EELP – Alberta Clipper US earnings are the Company’s earnings from its investment in EELP which undertook the project. The Alberta Clipper Project was placed into service on April 1, 2010. Alberta Clipper is a 1,670-kilometre (1,000 mile) crude oil pipeline that provides service between Hardisty, Alberta and Superior, Wisconsin with capacity of 450,000 bpd. RESULTS OF OPERATIONS Earnings from EELP – Alberta Clipper US were $38 million for the year ended December 31, 2012 compared with $42 million for both the years ended December 31, 2011 and 2010. These earnings, which represent the Company’s earnings from its 66.7% investment in a series of equity within EELP which owns the United States segment of Alberta Clipper, decreased due to a reduction in rates which took effect April 1, 2012. BUSINESS RISKS The risks identified below are specific to EEP and EELP. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks. SUPPLY AND DEMAND The profitability of EEP depends to some extent on the volume of products transported on its pipeline systems. The volume of shipments on EEP’s Lakehead System depends primarily on the supply of western Canadian crude oil and the demand for crude oil in the Great Lakes and Midwest regions of the United States and eastern Canada. Investment levels and related development activities by crude oil producers in conventional and oil sands production directly impacts the level of supply from the WCSB. Investment levels are influenced by crude oil producers’ expectations of crude oil prices, future operating costs, United States demand and availability of markets for produced crude oil. Demand depends, among other things, on weather, gasoline price and consumption, manufacturing levels, alternative energy sources and global supply disruptions. EEP’s natural gas gathering assets are also subject to changes in supply and demand for natural gas, NGL and related products. Commodity prices impact the willingness of natural gas producers to invest in additional infrastructure to produce natural gas and, with current low natural gas prices, infrastructure plans have been increasingly deferred or cancelled. These assets are also subject to competitive pressures from third-party and producer-owned gathering systems. Supply for the marketing operations depends to a large extent on the natural gas reserves and rate of drilling within the areas served by the natural gas business. Demand is typically driven by weather-related factors, with respect to power plant and utility customers, and industrial demand. EEP’s marketing business uses third party storage to balance supply and demand factors.

VOLUME RISK A decrease in volumes transported by EEP’s systems can directly and adversely affect revenues and results of operations. A decline in volumes transported can be influenced by factors beyond EEP’s control, including competition, regulatory actions, government actions, weather, storage levels, alternative energy sources, decreased demand, fluctuations in commodity prices, economic conditions, supply disruptions, availability of supply connected to the systems and adequacy of infrastructure to move supply into and out of the systems. To the extent commodity price differentials exist between markets serviced by the Company’s assets and other market hubs, producers may be incented to seek alternate transportation options, such as rail, thereby decreasing volumes available to ship on the Company’s systems. COMPETITION EEP’s Lakehead System, the United States portion of the liquids pipelines mainline, is a major crude oil export conduit from the WCSB. Other existing competing carriers and pipeline proposals to ship western Canadian liquids hydrocarbons to markets in the United States represent competition for the Lakehead System. Further details on such competing projects are described within Liquids Pipelines – Business Risks. EEP’s Mid-Continent and North Dakota systems also face competition from existing competing pipelines, proposed future pipelines and alternative gathering facilities, predominately rail, available to producers or the ability of the producers to build such gathering facilities. Competition for EEP’s storage facilities includes large integrated oil companies and other midstream energy partnerships. Other interstate and intrastate natural gas pipelines (or their affiliates) and other midstream businesses that gather, treat, process and market natural gas or NGL represent competition to EEP’s natural gas segment. The level of competition varies depending on the location of the gathering, treating and processing facilities. However, most natural gas producers and owners have alternate gathering, treating and processing facilities available to them, including those owned by competitors that are substantially larger than EEP. EEP’s marketing segment has numerous competitors, including large natural gas marketing companies, marketing affiliates of pipelines, major oil and natural gas producers, independent aggregators and regional marketing companies. REGULATION In the United States, the interstate oil pipelines owned and operated by EEP and certain activities of EEP’s intrastate natural gas pipelines are subject to regulation by the FERC or state regulators and its financial condition and results of operations could worsen if tariff rates were protested. While gas gathering pipelines are not currently subject to FERC rate regulation, proposals to more actively regulate intrastate gathering pipelines are currently being considered in certain of the states in which EEP operates. In addition, the FERC has also taken an interest in regulating gas gathering systems that connect into interstate pipelines. MARKET PRICE RISK EEP’s gas processing business is subject to commodity price risk arising from movements in natural gas and NGL prices and differentials. These risks have been managed by using physical and financial contracts to fix the prices of natural gas and NGL. Certain of these financial contracts do not qualify for cash flow hedge accounting and; therefore, EEP’s earnings are exposed to associated changes in the mark-to-market value of these contracts. 66 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 67 ENBRIDGE INCOME FUND The Fund is involved in the generation and transportation of energy through its crude oil and liquids pipeline and storage business in Western Canada (Liquids Transportation and Storage), interests in more than 500 MW of renewable power generation capacity and its 50% interest in Alliance Pipeline Canada. Liquids Transportation and Storage operates a crude oil gathering system and trunkline pipeline in southern Saskatchewan and southwestern Manitoba, connecting to Enbridge’s mainline pipeline to the United States (the Saskatchewan System). The Fund’s renewable power portfolio includes the 190-MW Ontario Wind Project, the 99-MW Talbot Wind Project and the 80-MW Sarnia Solar Project. In December 2012, the Fund completed the acquisition of crude oil storage facilities along with additional wind and solar energy assets from Enbridge and its whollyowned subsidiaries, as discussed below. CRUDE OIL STORAGE AND RENEWABLE ENERGY TRANSFERS In December 2012, ENF and the Fund finalized the acquisition of Hardisty Storage Caverns, Hardisty Contract Terminals, Greenwich, and Amherstburg and Tilbury projects from Enbridge and its wholly-owned subsidiaries for an aggregate purchase price of approximately $1.2 billion, financed in part by the issuance of additional ordinary trust units of the Fund to ENF and additional Enbridge Commercial Trust (ECT) preferred units to Enbridge. ENF in turn issued additional common shares to the public and to Enbridge. Enbridge also provided bridge debt financing (Bridge Financing) to the Fund for the balance of the purchase price, which was repaid in December 2012. Enbridge’s overall economic interest in the Fund was reduced from 69.2% to 67.7% upon completion of the transaction. In October 2011, the Fund also acquired the Ontario Wind, Sarnia Solar and Talbot Wind energy projects from a wholly-owned subsidiary of Enbridge for an aggregate price of approximately $1.2 billion. The transaction was financed by the Fund through a combination of debt and equity, including the issuance of additional ordinary trust units of the Fund to ENF and ECT preferred units to Enbridge. ENF in turn issued additional common shares to the public and to Enbridge. Enbridge’s overall economic interest in the Fund was reduced from 72.3% to 69.2% upon completion of the transaction and associated financing. The asset transfers described above occurred between entities under common control of Enbridge, and the intercompany gains realized by the selling entities in each of the years ended December 31, 2012 and 2011 have been eliminated from the Consolidated Financial Statements of Enbridge. Income taxes of $56 million and $98 million for the years ended December 31, 2012 and 2011, respectively, incurred on the related capital gains remain as charges to consolidated earnings. The Company retains the benefit of cash taxes paid in the form of increased tax basis of its investment in the underlying entities; however, accounting recognition of such benefit is not permitted until such time as the entities are sold outside of the consolidated group. Through these transactions, which essentially resulted in a partial monetization of these assets by Enbridge through sale to noncontrolling interests (being ENF’s public shareholders), Enbridge realized a source of funds of $213 million and $210 million, as presented within Financing Activities on the Consolidated Statements of Cash Flows for the years ended December 31, 2012 and 2011, respectively. In December 2012, the Fund issued $500 million in medium-term notes. The funds from this issuance, together with its cash on hand and draws on the Fund’s committed credit facility, were used to repay the $582 million Bridge Financing to Enbridge. ENBRIDGE INCOME FUND Fort St. John Regina Chicago Hardisty Edmonton Alliance Pipeline (Canada) Saskatchewan System Alliance Pipeline (US) NRGreen Waste-heat Power Generation Liquids Pipelines Gas Pipelines Crude Oil Storage Wind Assets Solar Assets Fo Ed ar g

SASKATCHEWAN SYSTEM SHIPPER COMPLAINT On December 17, 2010, the Saskatchewan System filed amended tariffs for the Westspur pipeline with the NEB with an effective date of February 1, 2011. In January 2011, a shipper on the Westspur system requested the NEB make the tolls “interim” effective February 1, 2011 pending discussions between the shipper and the Saskatchewan System on information requests put forward by the shipper. Subsequently, the shipper filed a complaint with the NEB on the basis that the information provided was not adequate to allow an assessment to be made of the reasonableness of the tolls. Six parties have filed letters with the NEB supporting the shipper’s complaint. As directed by the NEB, negotiation among the parties has been ongoing and as of February 14, 2013, the Fund continues to review the structure of its tolls with shippers. INCENTIVE AND MANAGEMENT FEES Enbridge receives an annual base management fee for administrative and management services it provides to the Fund, plus incentive fees. Incentive fees are paid to Enbridge based on cash distributions paid by the Fund that exceed a base distribution amount. In 2012, the Company received intercompany incentive fees of $12 million (2011 – $10 million; 2010 – $8 million) before income taxes. Enbridge also provides management services to ENF. No additional fee is charged to ENF for these services provided the Fund is paying a fee to Enbridge. CORPORATE RESTRUCTURING In 2010, a plan of arrangement (the Plan) to restructure the Fund took effect. Under the Plan all publicly held trust units and five million units held by Enbridge were exchanged on a one-for-one basis for shares of a taxable Canadian corporation, ENF. The business of ENF is generally limited to investment in the Fund. Following completion of the Plan, the Company retained its overall economic interest in the Fund and remained the primary beneficiary of the Fund both before and after the Plan through a combined direct and indirect investment in the Fund voting units and a non-voting preferred unit investment. As such, Enbridge continues to consolidate the Fund under variable interest entity accounting rules. RESULTS OF OPERATIONS Earnings from the Fund totaled $84 million for the year ended December 31, 2012 compared with $51 million for the year ended December 31, 2011. The increased earnings from the Fund reflected a full year of earnings from the assets acquired from a wholly-owned subsidiary of Enbridge in October 2011. Earnings also reflected the December 2012 transfer of Hardisty Storage Caverns, Hardisty Contract Terminals, Greenwich, Amherstburg and Tilbury projects. Partially offsetting the earnings contributions were increased interest costs, higher business development expense and non-cash deferred income taxes. Earnings from the Fund increased from $42 million for the year ended December 31, 2010 to $51 million in 2011. The increased earnings reflected increased contributions from the Saskatchewan System following substantial completion of its Phase II expansion project in December 2010, as well as contribution from the wind and solar resources acquired by the Fund in October 2011. These positive impacts were partially offset by higher operating and administrative costs as a result of the 2011 asset acquisition and an increase in interest expense and taxes. 68 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 69 BUSINESS RISKS Risks for Alliance Pipeline Canada are similar to those identified for Alliance Pipeline US in the Gas Pipelines, Processing and Energy Services segment. The following risks generally relate to the Saskatchewan System and the wind and solar businesses, as indicated. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks. SASKATCHEWAN SYSTEM COMPETITION The Saskatchewan System faces competition in pipeline transportation from other pipelines as well as other forms of transportation, most notably rail. These alternative transportation options could charge rates or provide service to locations that result in greater net profit for shippers, thereby reducing shipments on the Saskatchewan System or resulting in pressure to reduce tolls. The Saskatchewan System’s right-of-way and expansion efforts provide a competitive advantage and the Company believes its tolls are competitive relative to alternative pipeline transportation options; however, the Fund is currently engaged in discussions with shippers regarding the reasonableness of its tolls. REGULATION The Fund’s 50% interest in Alliance Pipeline Canada and certain pipelines within the Saskatchewan System are subject to the actions of various regulators, including the NEB. Actions of the regulators related to tariffs, tolls and facilities impact earnings and the success of expansion projects. Delays in regulatory approvals could result in cost escalations and construction delays. Changes in regulation, including decisions by regulators on the applicable tariff structure or changes in interpretations of existing regulations by courts or regulators, could adversely affect the results of operations of the Fund and could adversely impact the timing and amount of recovery or settlement of regulatory balances. WIND AND SOLAR REGULATION The Fund’s wind and solar assets which operate in Ontario are classified as intermittent generators under the Independent Electricity System Operator (IESO) market rules. IESO market rules allow delivery of electrical energy to the transmission and distribution grid as it is produced regardless of prevailing power price. Recent amendments to these market rules allow the IESO to curtail intermittent generators during periods of surplus base load generation when the prevailing power price falls below a threshold. As the wind and solar assets currently operate under long-term PPAs the Fund is in discussions with the Ontario Power Authority to determine its rights and obligations under its PPA for economic compensation during future periods of economic curtailment. AVAILABILITY OF TRANSMISSION The ability to deliver electricity is affected by the availability of the various transmission and distributions systems in the areas in which it operates. The failure of existing transmission or distribution facilities or lack of adequate transmission or distribution capacity could have a material adverse effect on the ability to deliver electricity and receive payment under the PPA. WEATHER Earnings from wind and solar projects are highly dependent on weather and atmospheric conditions. While the expected energy yields for the wind and solar projects are predicted using long-term historical data, wind and solar resources will be subject to natural variation from year to year and from season to season. Any prolonged reduction in wind or solar resources at any of the wind or solar facilities could lead to decreased earnings for the Fund. O C O P MPET N TIO TI TIT TI O R A LAT U REG N TIO ATI L G O REG ATI A LAT U G N TIO L O S O VA B AB R TRA TR TY A SS F A RA A LA A S L N SIO IS SM ANS Y LIT L BI AI R ER TH WEA EAT WEATH

Corporate EARNINGS 2012 2011 2010 (millions of Canadian dollars) Noverco 27 24 21 Other Corporate (55) (40) (46) Adjusted loss (28) (16) (25) Noverco – equity earnings adjustment (12) – – Noverco – changes in unrealized derivative fair value loss (10) – – Other Corporate – changes in unrealized derivative fair value gains/(loss) (22) (87) 25 Other Corporate – foreign tax recovery 29 – – Other Corporate – unrealized foreign exchange gains/(loss) on translation of intercompany balances, net (17) 24 40 Other Corporate – impact of tax rate changes (11) 6 – Other Corporate – tax on intercompany gain on sale (56) (98) – Earnings/(loss) attributable to common shareholders (127) (171) 40 Total adjusted loss from Corporate was $28 million for the year ended December 31, 2012 compared with adjusted losses of $16 million for the year ended December 31, 2011 and $25 million for the year ended December 31, 2010. Corporate earnings/(loss) were impacted by the following adjusting items: Earnings from Noverco for 2012 included an unfavourable equity earnings adjustment related to prior periods. Earnings from Noverco for 2012 included changes in the unrealized fair value loss of derivative financial instruments. Loss for each year included changes in the unrealized fair value gains and losses on derivative financial instruments related to forward foreign exchange risk management positions. Loss for 2012 were impacted by taxes related to a historical foreign investment. Loss for each year included net unrealized foreign exchange gains and losses on the translation of foreigndenominated intercompany balances. Loss for 2012 and 2011 reflected tax rate changes. Loss for 2012 and 2011 were impacted by tax on an intercompany gain of sale. See Sponsored Investments – Enbridge Income Fund – Crude Oil Storage and Renewable Energy Transfers for details of the transactions. NOVERCO At December 31, 2012, Enbridge owned an equity interest in Noverco through ownership of 38.9% (2011 – 38.9%; 2010 – 32.1%) of its common shares and an investment in preferred shares. Noverco is a holding company that owns approximately 71% of Gaz Metro Limited Partnership (Gaz Metro), a natural gas distribution company operating in the province of Quebec with interests in subsidiary companies operating gas transmission, gas distribution and power distribution businesses in the province of Quebec and the state of Vermont. Effective September 2010, Gaz Metro became a privately held limited partnership as a result of a reorganization of its publicly held partnership units, which were exchanged on a one-for-one basis for common shares in Valener Inc., a new publicly listed corporation. 70 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 71 Noverco also holds, directly and indirectly, an investment in Enbridge common shares. In early 2012, Noverco advised Enbridge that the substantial increase in the value of these shares over the last decade had resulted in a significant shift in the balance of Noverco’s asset mix. The Board of Directors of Noverco authorized its manager to sell a portion of its Enbridge common share holding and rebalance Noverco’s asset mix. On March 22, 2012, Noverco sold 22.5 million Enbridge common shares through a secondary offering. Enbridge’s share of the proceeds of approximately $317 million was received as a dividend from Noverco on May 18, 2012 and was used to pay a portion of the Company’s quarterly dividend on June 1, 2012. This portion of the quarterly dividend did not qualify for the enhanced dividend tax credit in Canada and, accordingly, was not designated as an “eligible dividend”. For United States tax purposes, the dividend was a “qualified dividend”. A significant portion of the Company’s earnings from Noverco is in the form of dividends on its preferred share investments which are based on the yield of 10-year Government of Canada bonds plus a margin of 4.3% to 4.4%. Virtually all of Noverco’s residual earnings are from Gaz Metro’s regulated assets. Rates for these natural gas and electricity distribution networks are established primarily using a cost-of-service method. Consequently, Gaz Metro’s profitability is dependent on its ability to invest in the development of its rate base and on the rates of return on deemed equity authorized by the regulatory agencies. Weather variations do not affect Noverco’s earnings as Gaz Metro is not exposed to weather risk. RESULTS OF OPERATIONS Noverco adjusted earnings were $27 million for the year ended December 31, 2012 compared with $24 million for the year ended December 31, 2011 and $21 million for the year ended December 31, 2010. Noverco adjusted earnings for each year reflected contributions from the Company’s increased preferred share investment and Noverco’s underlying gas distribution investments. OTHER CORPORATE Corporate also consists of the new business development activities, general corporate investments and financing costs not allocated to the business segments. Other corporate costs include dividends on preference shares as such dividends are a deduction in determining earnings attributable to common shareholders. PREFERENCE SHARE ISSUANCES Since July 2011, the Company has issued 146 million preference shares for gross proceeds of approximately $3,660 million with the following characteristics. See Liquidity and Capital Resources – Outstanding Share Data. Gross Proceeds Initial Yield Dividend 1 Per Share Base Redemption Value 2 Redemption and Conversion Option Date 2,3 Right to Convert Into 3,4 (Canadian dollars, unless otherwise stated) Series B 5 $500 million 4.0% $1.00 $25 June 1, 2017 Series C Series D 5 $450 million 4.0% $1.00 $25 March 1, 2018 Series E Series F 5 $500 million 4.0% $1.00 $25 June 1, 2018 Series G Series H 5 $350 million 4.0% $1.00 $25 September 1, 2018 Series I Series J 5 US$200 million 4.0% US$1.00 US$25 June 1, 2017 Series K Series L 5 US$400 million 4.0% US$1.00 US$25 September 1, 2017 Series M Series N 5 $450 million 4.0% $1.00 $25 December 1, 2018 Series O Series P 5 $400 million 4.0% $1.00 $25 March 1, 2019 Series Q Series R 5 $400 million 4.0% $1.00 $25 June 1, 2019 Series S 1 The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend per year, as declared by the Board of Directors of the Company. 2 The Company may at its option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on the Conversion Option Date and every fifth anniversary thereafter. 4 Holders will be entitled to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/365) x (90-day Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q) or 2.5% (Series S)); or US$25 x (number of days in quarter/365) x (90-day United States Government treasury bill rate + 3.1% (Series K) or 3.2% (Series M)). 5 See Liquidity and Capital Resources – Outstanding Share Data for dividends declared on December 6, 2012.

RESULTS OF OPERATIONS Other Corporate adjusted loss was $55 million for the year ended December 31, 2012 compared with $40 million for the year ended December 31, 2011. Although net Corporate segment financing costs decreased in 2012 compared with 2011, this decrease was more than offset by increased preference share dividends and higher personnel costs. Adjusted loss from Corporate was $40 million for the year ended December 31, 2011 compared with $46 million for the year ended December 31, 2010. The decreased adjusted loss reflected lower interest expense, partially offset by an increase in preference share dividends following the issuance of 38 million preference shares during the year, as well as higher tax expense. Liquidity and Capital Resources The maintenance of financial strength and flexibility is fundamental to Enbridge’s growth strategy, particularly in light of the unprecedented level of growth projects secured or under development. With continued volatility in global capital markets, the Company’s access to timely funding may be subject to risks from factors outside its control, including but not limited to, United States economic uncertainty and slow economic recovery. To mitigate such risks, the Company actively manages financing plans and strategies to ensure it maintains sufficient liquidity to meet routine operating and future capital requirements. The Company targets to maintain sufficient liquidity to bridge fund through any periods of protracted capital markets disruption, up to one year. In the near term, the Company generally expects to utilize cash from operations and the issuance of debt, commercial paper and/or credit facility draws to fund liabilities as they become due, finance capital expenditures, fund debt retirements and pay common and preference share dividends. The Company also maintains a longer horizon funding plan which considers growth capital needs and identifies potential sources of debt and equity funding alternatives, with the objective of maintaining access to low cost capital. Several of the Company’s growth projects that will be undertaken jointly with EEP will be funded 60% by Enbridge and 40% by EEP, with EEP having the option to reduce its funding and associated economic interest in the projects by up to 15% before June 30, 2013. Furthermore, within one year of the final in-service date of either the Eastern Access or Lakehead System Mainline Expansion projects, EEP will have the option to increase its economic interest held at those times in each project by up to 15%. In accordance with its funding plan, the Company has been active in the capital markets with the following issuances during 2012: Corporate – $2,710 million in preference shares; $400 million in common equity; $750 million of medium-term notes; Enbridge Pipelines Inc. (EPI) – $100 million Century Bond; $150 million of medium-term notes; ENF/the Fund – $213 million in ENF common equity; $1,199 million of medium-term notes in the Fund; and EEP – US$447 million in Class A common units. In addition to these debt and equity issuances, the Company received a $317 million one-time dividend from its investment in Noverco which resulted from Noverco’s disposal of Enbridge shares via a secondary offering, as well as the monetization of crude oil storage and renewable energy assets through sale to the Fund. To ensure ongoing liquidity and mitigate the risk of capital market disruption, Enbridge also has a significant amount of committed bank credit facilities which were further bolstered in 2012. The Company’s net available liquidity of $10,799 million at December 31, 2012 was inclusive of approximately $1,297 million of unrestricted cash and cash equivalents, net of bank indebtedness. In addition to ensuring adequate liquidity, the Company actively manages its bank funding sources to optimize pricing and other terms. The following table provides details of the Company’s credit facilities at December 31, 2012 and 2011. 72 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 73 2011 2012 Maturity Dates 1 Total Facilities Total Facilities Draws 2 Available (millions of Canadian dollars) Liquids Pipelines 2014 300 300 25 275 Gas Distribution 2014 717 712 590 122 Sponsored Investments 2014 – 2017 2,534 3,162 1,645 1,517 Corporate 2014 – 2017 5,653 9,108 1,520 7,588 9,204 13,282 3,780 9,502 Southern Lights project financing 3 2014 1,576 1,484 1,429 55 Total credit facilities 10,780 14,766 5,209 9,557 1 Total facilities include $35 million in demand facilities with no maturity date. 2 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility. 3 Total facilities inclusive of $60 million for debt service reserve letters of credit. The Company’s credit facility agreements include standard default and covenant provisions whereby accelerated repayment may be required if the Company were to default on payment or violate certain covenants. As in prior years, the Company expects to continue to comply with these provisions and therefore not trigger any early repayments. As at December 31, 2012, the Company was in compliance with all debt covenants. With increased borrowing, the Company actively manages certain financial ratios measuring the Company’s ability to service its debt from operating cash flows. The Company’s internal cash flow growth maintains the financial ratios at a strong level. The Company’s access to liquidity from diversified funding sources and its ability to service its debt has allowed it to maintain a stable risk profile, which has led to sustained investment-grade ratings from the major credit rating agencies. The Company also continues to manage its debt-to-capitalization ratio to maintain a strong balance sheet. The Company’s debt-to-capitalization ratio, including bank indebtedness and short-term borrowings, was 61.4% at December 31, 2012 compared with 65.6% at December 31, 2011. The Company invests a portion of its surplus cash in short-term investment grade instruments with creditworthy counterparties. Short-term investments were $950 million as at December 31, 2012 compared with $73 million as at December 31, 2011. This $877 million increase was due to the timing of cash generated from debt and equity market transactions and will be used to fund the Company’s growth projects in 2013. There are no material restrictions on the Company’s cash with the exception of restricted cash of $7 million related to Southern Lights project financing and cash in trust of $12 million for specific shipper commitments. Excluding current maturities of long-term debt, the Company had a positive working capital position of $183 million at December 31, 2012 compared to negative working capital of $164 million for the year ended December 31, 2011. Working capital includes the current portion of unrealized fair value derivative gains and losses related to the Company’s risk management activities. The net liability position for current derivatives was $692 million and $394 million for the years ended December 31, 2012 and 2011, respectively. Actual cash outflows to be incurred to settle these liabilities depend on foreign exchange rates, interest rates or commodity prices in effect when derivative contracts outstanding mature; therefore, working capital at a point in time may not be representative of actual future cash flows. Further, working capital will fluctuate from time to time due to natural gas inventory and borrowing levels at EGD, which in turn are impacted by weather and commodity prices, as well as general activity levels within the Company’s Energy Services businesses, among others. Changes in commodity prices also impact accounts receivable and other, inventory and accounts payable and other within Energy Services and EGD.

December 31, 2012 2011 (millions of Canadian dollars) Cash and cash equivalents 1 1,795 740 Accounts receivable and other 2 4,026 4,084 Inventory 779 823 Bank indebtedness (479) (102) Short-term borrowings (583) (548) Accounts payable and other 3 (5,052) (4,801) Interest payable (196) (185) Environmental liabilities (107) (175) Working capital 183 (164) 1 Includes short-term investments and restricted cash of amounts in trust. 2 Includes Accounts receivable from affiliates. 3 Includes Accounts payable to affiliates. The net available liquidity, together with cash from operations and the proceeds of capital market transactions, is expected to be sufficient to finance all currently secured capital projects and provide flexibility for new investment opportunities in the short-term, in the event of unforeseen economic disturbances. OPERATING ACTIVITIES Cash provided by operating activities for the year ended December 31, 2012 was $2,874 million compared with $3,371 million for the year ended December 31, 2011 and $1,877 for the year ended December 31, 2010. The most significant factor which impacted the decline in cash provided by operating activities was a $1,063 million unfavourable variance in the changes in operating assets and liabilities. Working capital fluctuated due to variations in commodity prices and sales volumes within Energy Services, the timing of tax payments, the payment of power deposits to support the Company’s growth projects, as well as general variations in activity levels within the Company’s businesses. In addition, cash from operating activities during the fourth quarter of 2012 included an outflow of US$202 million related to a voluntary pre-payment of certain derivative liabilities. The payment was transacted to optimize cash management opportunities and did not alter the risk management properties of the derivative position. The cash outflows within operating activities were partially offset by the favourable operating performance of the Canadian Mainline under CTS, strong volumes across all of the Company’s liquids pipelines assets and general cash growth from development projects placed in service in recent years. Additionally, the Company received a $317 million one-time dividend from its investment in Noverco. During 2012, Noverco had realized a substantial gain on the disposition of a portion of its investment in Enbridge shares and subsequently distributed the proceeds from this transaction to its shareholders, by way of dividend. CASH PROVIDED BY OPERATING ACTIVITIES (millions of Canadian dollars) 1 Financial information has been extracted from financial statements prepared in accordance with U.S. GAAP. 2 Financial information has been extracted from financial statements prepared in accordance with Canadian GAAP. 1,372 2 2,017 2 1,877 1 3,371 1 2,874 1 12 11 10 09 08 74 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 75 INVESTING ACTIVITIES Cash used in investing activities was $6,204 million for the year ended December 31, 2012 compared with $5,079 million and $3,902 million for the corresponding periods of 2011 and 2010, respectively. Cash used in investing activities has increased on a year-over-year basis primarily due to capital expenditure activity, predominantly directed to the construction of the Company’s expansion initiatives, all of which are described in Growth Projects – Commercially Secured Projects and Growth Projects – Other Projects Under Development. A summary of additions to property, plant and equipment for the years ended December 31, 2012, 2011 and 2010 is as follows: Year ended December 31, 2012 2011 2010 (millions of Canadian dollars) Liquids Pipelines 2,091 955 684 Gas Distribution 438 483 387 Gas Pipelines, Processing and Energy Services 837 850 1,114 Sponsored Investments 1,993 1,187 868 Corporate 109 33 – Total capital expenditures 5,468 3,508 3,053 Other notable investing activities in 2012 included the acquisition of Silver State and PRA Gas Development, as well as the remaining 10% interest in Greenwich, for $340 million. The Company also provided additional funding of $531 million to various investments and joint ventures, namely TEP and Seaway Pipeline. In comparison, for the year ended December 31, 2011, the Company acquired its original 50% interest in Seaway Pipeline for $1,192 million, increased its Noverco preferred shares investment by $144 million and provided additional funding of $179 million to various equity investments. In 2010, the cash used in investing activities included the acquisition of Elk City System for $705 million. FINANCING ACTIVITIES Cash generated from financing activities was $4,395 million for the year ended December 31, 2012 compared with $2,030 million and $1,957 million for the corresponding periods of 2011 and 2010, respectively. The increase in cash provided by financing activities was primarily due to the issuance of redeemable preference shares of $2,634 million in 2012, compared with $926 million in 2011 and nil in 2010, as well as a common equity issuance of $384 million. This cash inflow was partially offset by payments of common and preference share dividends of $690 million in 2012 (2011 – $537 million; 2010 – $433 million). In 2012, the Company was also successful in issuing debenture and term notes for net proceeds of $2,199 million (2011 – $1,604 million; 2010 – $3,220 million), as well as making draws on short-term borrowings and bank indebtedness of $412 million (2011 – $224 million; 2010 – $165 million repayment). This was partially offset by repayments of term notes, commercial paper and credit facility draws of $803 million in 2012 (2011 – $864 million; 2010 – $843 million). Funds for debt retirements are generated through cash provided from operating activities as well as through the issuance of replacement debt. CAPITAL EXPENDITURES AND INVESTMENTS (millions of Canadian dollars) 12 11 10 3,053 3,508 5,468 Liquids Pipelines Gas Distribution Gas Pipelines, Processing and Energy Services Sponsored Investments Corporate

Cash generated from financing activities for the years ended December 31, 2012 and 2011 also included contributions, net of distributions, from third-party investors in the Fund of $164 million and $175 million, respectively. In both 2012 and 2011, the Fund acquired certain crude oil storage and renewable energy assets from Enbridge, which it financed in part through the issuance of equity to its public noncontrolling interest holders. In 2012, the Company also received contributions, net of distributions, from third-party investors, primarily from EEP, of $27 million (2011 – $518 million; 2010 – $121 million). Participants in the Company’s Dividend Reinvestment and Share Purchase Plan receive a 2% discount on the purchase of common shares with reinvested dividends. For the year ended December 31, 2012, dividends declared were $895 million (2011 – $759 million), of which $597 million (2011 – $530 million) were paid in cash and reflected in financing activities. The remaining $297 million (2011 – $229 million) of dividends declared were reinvested pursuant to the plan and resulted in the issuance of common shares rather than a cash payment. For the years ended December 31, 2012 and 2011, 33.2% and 30.2%, respectively, of total dividends declared were reinvested. OUTSTANDING SHARE DATA 1 Number Preference Shares, Series A 2 5,000,000 Preference Shares, Series B 2,3 20,000,000 Preference Shares, Series D 2,4 18,000,000 Preference Shares, Series F 2,5 20,000,000 Preference Shares, Series H 2,6 14,000,000 Preference Shares, Series J 2,7 8,000,000 Preference Shares, Series L 2,8 16,000,000 Preference Shares, Series N 2,9 18,000,000 Preference Shares, Series P 2,10 16,000,000 Preference Shares, Series R 2,11 16,000,000 Common Shares – issued and outstanding (voting equity shares) 806,456,150 Stock Options – issued and outstanding (14,611,123 vested) 31,907,543 1 Outstanding share data information is provided as at February 8, 2013. 2 All preference shares are non-voting equity shares. Preference Shares, Series A may be redeemed any time at the Company’s option. For all other series of Preference Shares, the Company may at its option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter. 3 On June 1, 2017, and on June 1 every five years thereafter, the holders of Preference Shares, Series B will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series B into an equal number of Cumulative Redeemable Preference Shares, Series C. 4 On March 1, 2018, and on March 1 every five years thereafter, the holders of Preference Shares, Series D will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series D into an equal number of Cumulative Redeemable Preference Shares, Series E. 5 On June 1, 2018, and on June 1 every five years thereafter, the holders of Preference Shares, Series F will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series F into an equal number of Cumulative Redeemable Preference Shares, Series G. 6 On September 1, 2018, and on September 1 every five years thereafter, the holders of Preference Shares, Series H will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series H into an equal number of Cumulative Redeemable Preference Shares, Series I. 7 On June 1, 2017, and on June 1 every five years thereafter, the holders of Preference Shares, Series J will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series J into an equal number of Cumulative Redeemable Preference Shares, Series K. 8 On September 1, 2017, and on September 1 every five years thereafter, the holders of Preference Shares, Series L will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series L into an equal number of Cumulative Redeemable Preference Shares, Series M. 9 On December 1, 2018, and on December 1 every five years thereafter, the holders of Preference Shares, Series N will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series N into an equal number of Cumulative Redeemable Preference Shares, Series O. 10 On March 1, 2019, and on March 1 every five years thereafter, the holders of Preference Shares, Series P will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series P into an equal number of Cumulative Redeemable Preference Shares, Series Q. 11 On June 1, 2019 and on June 1 every five years thereafter, the holders of Preference Shares, Series R will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series R into an equal number of Cumulative Redeemable Preference Shares, Series S. 76 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 77 Effective May 25, 2011, a two-for-one stock split of the Company’s common shares was completed. All references to the number of shares outstanding, earnings per common share, diluted earnings per common share, adjusted earnings per common share, dividends per common share and outstanding option information have been retroactively restated to reflect the impact of the stock split. On December 6, 2012, the Enbridge Board of Directors declared the following quarterly dividends. All dividends are payable on March 1, 2013 to shareholders of record on February 15, 2013. Common Shares $0.31500 Preference Shares, Series A $0.34375 Preference Shares, Series B $0.25000 Preference Shares, Series D $0.25000 Preference Shares, Series F $0.25000 Preference Shares, Series H $0.25000 Preference Shares, Series J US$0.25000 Preference Shares, Series L US$0.25000 Preference Shares, Series N $0.25000 Preference Shares, Series P $0.25000 Preference Shares, Series R 1 $0.23560 1 This first dividend declared for the Preference Shares, Series R includes accrued dividends from December 5, 2012, the date the shares were issued. The regular quarterly dividend of $0.25 per share will take effect on June 1, 2013. See Corporate – Other Corporate – Preference Share Issuances. Commitments and Contingencies CAPITAL EXPENDITURE COMMITMENTS The Company has signed contracts for the purchase of services, pipe and other materials, as well as transportation, totaling $4,639 million which are expected to be paid over the next five years. CONTRACTUAL OBLIGATIONS Payments due for contractual obligations over the next five years and thereafter are as follows: Total Less than 1 year 1 – 3 years 3 – 5 years After 5 years (millions of Canadian dollars) Long-term debt 1 21,428 1,234 2,195 2,320 15,679 Capital and operating leases 329 40 80 72 137 Long-term contracts 2,3 5,691 3,322 925 421 1,023 Pension obligations 4 140 140 – – – Total contractual obligations 27,588 4,736 3,200 2,813 16,839 1 Excludes interest. Changes to the planned funding requirements are dependent on the terms of any debt refinancing agreements. 2 Approximately $2,507 million of these contracts are commitments for materials related to the construction of growth projects. Changes to the planned funding requirements, including cancellation, are dependent on changes to the related projects. 3 Contracts totaling $161 million are within proportionately consolidated joint venture entities and contracts totaling $88 million are within equity investments which the Company is guaranteeing. 4 Assumes only required payments will be made into the pension plans in 2013. Contributions are made in accordance with independent actuarial valuations as at December 31, 2012. Contributions, including discretionary payments, may vary pending future benefit design and asset performance.

UNITED STATES LEGAL AND REGULATORY PROCEEDINGS A number of United States governmental agencies and regulators have initiated investigations into the Line 6A and Line 6B crude oil releases. Approximately 30 actions or claims have been filed against Enbridge, EEP or their affiliates in United States federal and state courts in connection with the Line 6B crude oil release, including direct actions and actions seeking class status. Based on the current status of these cases, EEP does not expect the outcome of these actions to be material. On July 2, 2012, PHMSA announced a NOPV related to the Line 6B crude oil release, including a civil penalty of US$3.7 million that EEP paid in the third quarter of 2012. One claim related to the Line 6A crude oil release has been filed against Enbridge, EEP or their affiliates by the State of Illinois in the Illinois state court. The parties are currently operating under an agreed interim order. As at December 31, 2012, the Company was not aware of any claims related to the Line 14 crude oil release. See Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases and Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Line 14 Crude Oil Release. ENBRIDGE GAS NEW BRUNSWICK INC. REGULATORY MATTERS In 2011, the Government of New Brunswick passed legislation related to the regulatory process for setting rates for gas distribution within the province. A final rates and tariffs regulation was subsequently enacted by the Government of New Brunswick in April 2012. Based on the amended rate setting methodology and specific conditions outlined therein, EGNB no longer met the criteria for the continuation of rate-regulated accounting. As a result, the Company eliminated from its 2011 Consolidated Statements of Financial Position a deferred regulatory asset and certain capitalized operating costs totaling $262 million, net of tax. In April 2012, the Company, Enbridge EEDI and EGNB commenced an action against the Province of New Brunswick in the New Brunswick Court of Queen’s Bench, claiming damages as a result of the continuing breaches by the province of the General Franchise Agreement it signed with Enbridge in 1999. Additionally, on May 2, 2012, the Company, EEDI and EGNB filed a Notice of Application with the New Brunswick Court of Queen’s Bench seeking a declaration from the Court that the rates and tariffs regulation is invalid. In a decision released on August 23, 2012, the Court dismissed EGNB’s application. EGNB has filed a Notice of Appeal with the New Brunswick Court of Appeal and a hearing of the appeal is expected to be held during the first half of 2013. There is no assurance these actions will be successful or will result in any recovery. See Gas Distribution – Other Gas Distribution and Storage – Enbridge Gas New Brunswick Inc. – Regulatory Matters. TAX MATTERS Enbridge and its subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in the Company’s view, these tax positions, if challenged by tax authorities, may not be fully sustained on review. OTHER LEGAL AND REGULATORY PROCEEDINGS The Company and its subsidiaries are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. While the final outcome of such actions and proceedings cannot be predicted with certainty, Management believes that the resolution of such actions and proceedings will not have a material impact on the Company’s consolidated financial position or results of operations. 78 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 79 Quarterly Financial Information 1 2012 Q1 Q2 Q3 Q4 Total (millions of Canadian dollars, except for per share amounts) Revenues 6,627 5,718 5,788 7,173 25,306 Earnings attributable to common shareholders 264 11 189 146 610 Earnings per common share 0.35 0.01 0.24 0.19 0.79 Diluted earnings per common share 0.34 0.01 0.24 0.18 0.78 Dividends per common share 0.2825 0.2825 0.2825 0.2825 1.13 EGD – warmer/(colder) than normal weather 24 – – (1) 23 Changes in unrealized derivative fair value and intercompany foreign exchange loss 110 252 93 81 536 2011 Q1 Q2 Q3 Q4 Total (millions of Canadian dollars, except for per share amounts) Revenues 6,529 6,938 6,277 7,309 27,053 Earnings attributable to common shareholders 364 302 (5) 159 820 Earnings per common share 2 0.49 0.40 (0.01) 0.21 1.09 Diluted earnings per common share 2 0.48 0.40 (0.01) 0.21 1.08 Dividends per common share 2 0.2450 0.2450 0.2450 0.2450 0.98 EGD – warmer/(colder) than normal weather (11) (2) – 12 (1) Changes in unrealized derivative fair value and intercompany foreign exchange (gains)/loss (18) (18) 242 (241) (35) 1 Quarterly financial information has been extracted from financial statements prepared in accordance with U.S. GAAP. 2 Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011. Several factors impact comparability of the Company’s financial results on a quarterly basis, including, but not limited to, seasonality in the Company’s gas distribution businesses, fluctuations in market prices such as foreign exchange rates and commodity prices, disposals of investments or assets and the timing of in-service dates of new projects. EGD and the Company’s other gas distribution businesses are subject to seasonal demand. A significant portion of gas distribution customers use natural gas for space heating; therefore, volumes delivered and resulting revenues and earnings typically increase during the winter months of the first and fourth quarters of any given year. Revenues generated by EGD and other gas distribution businesses also vary from quarter-to-quarter with fluctuations in the price of natural gas, although earnings remain neutral due to the pass through nature of these costs. Gas Distribution’s earnings for the fourth quarter of 2011 included an extraordinary charge totaling $262 million, after-tax, as a result of the discontinuance of rate-regulated accounting at EGNB and the related write-off of a deferred regulatory asset and certain capitalized operating costs. The Company actively manages its exposure to market price risks including, but not limited to, commodity prices and foreign exchange rates. To the extent derivative instruments used to manage these risks are non-qualifying for the purposes of applying hedge accounting, changes in unrealized fair value gains and losses on these instruments will impact earnings.

In the fourth quarter of 2012, the Company recorded an impairment charge of $166 million ($105 million after-tax) related to certain of its Offshore assets, predominantly located within the Stingray and Garden Banks corridors. The Company had been pursuing alternative uses for these assets; however, due to changing competitive conditions in the fourth quarter of 2012, the Company concluded that such alternatives were no longer likely to proceed. Also included in the fourth quarter of 2012 was a $63 million gain on recognition of a regulatory asset related to OPEB within EGD. Fourth quarter earnings for 2012 and 2011 were also impacted by the impact of asset transfers between entities under common control of Enbridge, resulting in income taxes of $56 million and $98 million, respectively, incurred on the related capital gains. Reflected in earnings is the Company’s share of leak remediation costs and lost revenue associated with the Lines 6A, 6B and Line 14 crude oil releases. For the second, third and fourth quarter of 2012, these amounts were $2 million, $7 million and nil (2011 – $6 million, $21 million and $6 million), respectively. Earnings also reflected insurance recoveries associated with the Line 6B crude oil release of $24 million in the third quarter of 2012 and $5 million, $3 million, $13 million and $29 million in the first, second, third and fourth quarters of 2011, respectively. Finally, the Company is in the midst of a substantial capital program and the timing of construction and completion of growth projects may impact the comparability of quarterly results. The Company’s capital expansion initiatives, including construction commencement and in-service dates, are described in Growth Projects – Commercially Secured Projects and Growth Projects – Other Projects Under Development. Related Party Transactions All related party transactions are provided in the normal course of business and, unless otherwise noted, are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. Vector, a joint venture, contracts the services of Enbridge to operate the pipeline. Amounts for these services, which are charged at cost in accordance with service agreements, were $4 million for the year ended December 31, 2012 (2011 – $6 million; 2010 – $7 million). Certain wholly-owned subsidiaries within the Gas Distribution and Gas Pipelines, Processing and Energy Services segments have transportation commitments with several joint venture affiliates that are accounted for using the equity method. Total amounts charged for transportation services were $127 million, $106 million and $102 million for the years ended December 31, 2012, 2011 and 2010, respectively. Amounts receivable from affiliates include a series of loans to Vector totaling $178 million (2011 – $190 million), included in Deferred amounts and other assets, which require quarterly interest payments at annual interest rates from 5% to 8%. Risk Management and Financial Instruments MARKET PRICE RISK The Company’s earnings, cash flows, and other comprehensive income (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and the Company’s share price (collectively, market price risk). Formal risk management policies, processes and systems have been designed to mitigate these risks. The following summarizes the types of market price risks to which the Company is exposed and the risk management instruments used to mitigate them. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below. 80 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 81 FOREIGN EXCHANGE RISK The Company’s earnings, cash flows and OCI are subject to foreign exchange rate variability, primarily arising from its United States dollar denominated investments and subsidiaries, and certain revenues denominated in United States dollars and certain expenses denominated in Euros. The Company has implemented a policy whereby it economically hedges a minimum level of foreign currency denominated earnings exposures identified over the next five year period. The Company may also hedge anticipated foreign currency denominated purchases or sales and foreign currency denominated debt, as well as certain equity investment balances and net investments in foreign denominated subsidiaries. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage variability in cash flows arising from its United States dollar investments and subsidiaries, and primarily non-qualifying derivative instruments to manage variability arising from certain revenues denominated in United States dollars. INTEREST RATE RISK The Company’s earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of its variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps and options are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense through 2016 with an average swap rate of 2.2%. The Company’s earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate its exposure to long-term interest rate variability on select forecast term debt issuances through 2016. Future fixed rate term debt issuances of $10,547 million have been hedged at an average swap rate of 3.5%. The Company also monitors its debt portfolio mix of fixed and variable rate debt instruments to maintain a consolidated portfolio of debt which stays within its Board of Directors approved policy limit band of a maximum of 25% floating rate debt as a percentage of total debt outstanding. The Company uses primarily qualifying derivative instruments to manage interest rate risk. COMMODITY PRICE RISK The Company’s earnings and cash flows are exposed to changes in commodity prices as a result of ownership interests in certain assets and investments, as well as through the activities of its energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. The Company employs financial derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. The Company uses primarily non-qualifying derivative instruments to manage commodity price risk. EQUITY PRICE RISK Equity price risk is the risk of earnings fluctuations due to changes in the Company’s share price. The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, Restricted Stock Units. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.

THE EFFECT OF DERIVATIVE INSTRUMENTS ON THE STATEMENTS OF EARNINGS AND COMPREHENSIVE INCOME The following table presents the effect of derivative instruments on the Company’s consolidated earnings and consolidated comprehensive income. Year ended December 31, 2012 2011 2010 (millions of Canadian dollars) Amount of unrealized gains/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts (12) (22) (25) Interest rate contracts (46) (724) (217) Commodity contracts 52 72 128 Other contracts (3) 6 (1) Net investment hedges Foreign exchange contracts 1 (26) 19 (8) (694) (96) Amount of (gains)/loss reclassified from Accumulated other comprehensive income (AOCI) to earnings (effective portion) Cash flow hedges Foreign exchange contracts 1 1 1 (7) Interest rate contracts 2 (1) (10) 61 Commodity contracts 3 (3) (55) (116) Other contracts 4 2 (2) 1 (1) (66) (61) Amount of (gains)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing) Cash flow hedges Interest rate contracts 2 23 11 – Commodity contracts 3 (3) 5 (3) 20 16 (3) Amount of gains/(loss) from non-qualifying derivatives included in earnings Foreign exchange contracts 1 120 (179) 33 Interest rate contracts 2 (2) 9 (3) Commodity contracts 3 (765) 280 (12) Other contracts 4 (2) 4 – (649) 114 18 1 Reported within Transportation and other services revenues and Other income in the Consolidated Statements of Earnings. 2 Reported within Interest expense in the Consolidated Statements of Earnings. 3 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. 82 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 83 LIQUIDITY RISK Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including commitments and guarantees, as they become due. In order to manage this risk, the Company forecasts cash requirements over a 12 month rolling time period to determine whether sufficient funds will be available. The Company’s primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt which includes debentures and medium-term notes. The Company maintains current shelf prospectuses with securities regulators, which enables, subject to market conditions, ready access to either the Canadian or United States public capital markets. In addition, the Company maintains sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables the Company to fund all anticipated requirements for one year without accessing the capital markets. The Company is in compliance with all the terms and conditions of its committed credit facilities as at December 31, 2012. As a result, all credit facilities are available to the Company and the banks are obligated to fund and have been funding the Company under the terms of the facilities. CREDIT RISK Entering into derivative financial instruments may result in exposure to credit risk. Credit risk arises from the possibility that a counterparty will default on its contractual obligations. The Company enters into risk management transactions primarily with institutions that possess investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated by credit exposure limits and contractual requirements, frequent assessment of counterparty credit ratings and netting arrangements. The Company generally has a policy of entering into individual International Swaps and Derivatives Association agreements, or other similar derivative agreements, with the majority of its derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit event, and would reduce the Company’s credit risk exposure on derivative asset positions outstanding with these counterparties in these particular circumstances. Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Within Gas Distribution, credit risk is mitigated by the large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. The Company actively monitors the financial strength of large industrial customers and, in select cases, has obtained additional security to minimize the risk of default on receivables. Generally, the Company classifies and provides for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value. FAIR VALUE MEASUREMENTS The Company uses the most observable inputs available to estimate the fair value of its derivatives. When possible, the Company estimates the fair value of its derivatives based on quoted market prices. If quoted market prices are not available, the Company uses estimates from third party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, the Company uses standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, the Company uses observable market prices (interest, foreign exchange, commodity and share) and volatility as primary inputs to these valuation techniques. Finally, the Company considers its own credit default swap spread as well as the credit default swap spreads associated with its counterparties in its estimation of fair value.

GENERAL BUSINESS RISKS STRATEGIC AND COMMERCIAL RISKS PUBLIC OPINION The Company’s reputation is one of its most valuable assets. Public opinion or reputation risk is the risk of negative impacts on the Company’s business, operations or financial condition resulting from changes in the Company’s reputation with stakeholders, special interest groups, political leadership, the media or other entities. Public opinion may be influenced by media attention directed to development projects such as Northern Gateway. Potential impacts of a negative public opinion may include loss of business, legal action, increased regulatory oversight and costs. Reputation risk often arises as a consequence of some other risk event, such as in connection with operational, regulatory or legal risks. Therefore, reputation risk cannot be managed in isolation from other risks. The Company manages reputation risk by: having formal risk management policies, procedures and systems in place to identify, assess and mitigate risks to the Company; operating to the highest ethical standards, with integrity, honesty and transparency, and maintaining positive relationships with customers, investors, employees, partners, regulators and other stakeholders; having health, safety and environment management systems in place, as well as policies, programs and practices for conducting safe and environmentally sound operations; having strong corporate governance practices, including a Statement on Business Conduct, with which all employees are required to certify their compliance on an annual basis, and whistleblower procedures, which allow employees to report suspected ethical concerns on a confidential and anonymous basis; and pursuing socially responsible operations as a longer-term corporate strategy (implemented through the Company’s CSR Policy, Climate Change Policy, Aboriginal and Native American Policy and the Neutral Footprint Initiative). PROJECT EXECUTION As the Company increases its slate of growth projects, it continues to focus on completing projects safely, on-time and on-budget. However, the Company faces the challenge of scaling the business to manage an unprecedented number of commercially secured growth projects. The Company’s ability to successfully execute the development of its organic growth projects may be influenced by capital constraints, third-party opposition, changes in shipper support over time, delays in or changes to government and regulatory approvals, cost escalations, construction delays, inadequate resources and in-service delays (collectively, Execution Risk). Customer trends are toward expecting the Company to assume more risk and accept lower returns. Early stage project risks include right-of-way procurement, special interest group opposition, Crown consultation and environmental and regulatory permitting. Cost escalations or missed in-service dates on future projects may impact future earnings and may hinder the Company’s ability to secure future projects. Construction delays due to regulatory delays, contractor or supplier non-performance and weather conditions may impact project development. The Company strives to be an industry leader in project execution through its Major Projects group. Major Projects is centralized and has a clearly defined governance structure and process for all major projects, with dedicated resources organized to lead and execute each major project. Capital constraints and cost escalation risks are mitigated through structuring of commercial agreements, typically where shippers retain complete or a share of capital cost excess. Early stage project risks are mitigated by early assessment of stakeholder issues to develop proactive relationships and specific action plans. Detailed cost tracking and centralized purchasing is used on all major projects to facilitate optimum pricing and service terms. Strategic relationships have been developed with suppliers and contractors. Enhanced recruiting, and outsourcing where necessary, has been introduced to ensure sufficient resources to address the increasing volume of growth projects. 84 < ENBRIDGE INC. 2012 FINANCIAL REPORT O O P P B C U L N I N I I C O CT OJ PR TI EXE UT EC ON XEC EX T

Management’s Discussion and Analysis > 85 PLANNING AND INVESTMENT ANALYSIS The Company evaluates the value proposition for expansion projects, new acquisitions or divestitures on an ongoing basis. Planning and investment analysis is highly dependent on accurate forecasting assumptions and to the extent that these assumptions do not materialize, financial performance may be lower or more volatile than expected. Volatility in the economy, change in cost estimates, project scoping and risk assessment could result in a loss in profits for the Company. Large scale acquisitions may involve significant pricing and integration risk. The planning and investment analysis process involves all levels of management and Board of Directors’ review to ensure alignment across the Company. A centralized corporate development group which is appropriately staffed rigorously evaluates all major investment proposals with consistent due diligence processes, including a thorough review of the asset quality, systems and financial performance of the assets being assessed. HUMAN RESOURCES As growth in WCSB production maintains its momentum it has presented both opportunities and challenges for the Company. In response to the demands of the announced list of growth projects, the Company expects to add approximately 2,500 permanent additions to its workforce over the next five years. However, the robust economic situation in Alberta has led to a substantially tighter employment market in the province. As the Company continues through a period of growth, attracting and retaining adequate personnel who adhere to Enbridge’s values will be critical to fulfilling the Company’s growth plan. ECONOMIC REGULATION Many of the Company’s pipeline operations are regulated and are subject to regulatory risk. The nature and degree of regulation and legislation affecting energy companies in Canada and the United States has changed significantly in past years and there is no assurance that further substantial changes will not occur. These changes may adversely affect toll structures or other aspects of pipeline operations or the operations of shippers. Recently, shippers have challenged toll increases on various pipelines owned by Enbridge and some of Enbridge’s competitors. Enbridge retains dedicated professional staff and maintains strong relationships with customers, interveners and regulators to help minimize economic and regulation risk. OPERATIONAL RISKS ENVIRONMENTAL INCIDENT An environmental incident could have lasting reputational impacts to Enbridge and could impact its ability to work with various stakeholders. In addition to the cost of remediation activities (to the extent not covered by insurance) environmental incidents may lead to an increased cost of operation and insuring the Company’s assets, thereby negatively impacting earnings. The Company mitigates risk of environmental incident through its ORM Plan, which broadly aims to position Enbridge as the industry leader for system integrity, environmental and safety programs. Through the ORM Plan, the Company has expanded its maintenance, excavation and repair programs which are supported by operating and capital budgets directed to pipeline integrity. Emergency response plans, operator training and landowner education programs are included in the Company’s response preparedness. The Company also recently completed a new state-of-the-art control centre. The new control centre was designed with enhanced security measures. The Company also revised and enhanced all of its control room procedures pertaining to decision making, pipeline start-ups and shutdowns, leak detection system alarms, communication protocols and suspected column separations. The Company contributes to research and development initiatives for technological advances to further enhance safety and integrity of pipelines. S S P D EN E G A N A A A S Y N L VE V I YS L NA T N M TM T E N I N N I N ES O U R RES CES A MA C U AN H O O O IC R G A LAT C C U N EC TIO ATI L REG M NO O D R A TA C VI T ENT EN CI NC I AL ENT EN M ON ENV EN

The Company maintains comprehensive insurance coverage for its subsidiaries and affiliates which renews annually. The program includes commercial liability insurance coverage that is consistent with coverage considered customary for its industry and includes coverage for environmental incidents. The total insurance coverage will be allocated on an equitable basis in the unlikely event multiple insurable incidents exceeding the Company’s coverage limits are experienced by Enbridge subsidiaries or affiliates within the same insurance period. PUBLIC, WORKER AND CONTRACTOR SAFETY Several of the Company’s pipeline systems run adjacent to populated areas and a major incident could result in injury to members of the public. A public safety incident could result in reputational damage to the Company, material repair costs or increased costs of operating and insuring the Company’s assets. The safety of the Company’s current and future personnel is a Company priority. As part of the ORM Plan, the Company initiated Enbridge’s Life Saving Rules. The Life Saving Rules are designed to highlight key processes and rules to ensure public, worker and contractor safety. The Company also introduced new Safety Culture training sessions for all employees. Also, within EGD, the Company completed construction of the Enbridge Operations and Technology Centre in 2012. The new training facility provides employees real-life simulations of major incidents and teaches the appropriate actions to resolve them in a safe and controlled environment. Additionally, in 2012, EGD’s on-going pipeline integrity program completed the replacement of all remaining cast iron and bare steel pipe in its gas distribution system. SERVICE INTERRUPTION INCIDENT A service interruption due to a major power disruption or curtailment on commodity supply could have a significant impact on the Company’s ability to operate its assets. Specifically, for Gas Distribution, any prolonged interruptions would ultimately impact gas distribution customers. The Company mitigates service interruption risk through its diversified sources of supply, storage withdrawal flexibility, backup power systems, critical parts inventory and redundancies for critical equipment. SYSTEMS SECURITY INCIDENT The Company’s infrastructure, applications and data are becoming more integrated, creating increased risk a failure in one system could lead to a failure of another system. There is also increasing industry-wide cyber-attacking activities targeting industrial control systems. A successful cyber-attack could lead to unavailability, disruption or loss of key functionalities within the Company’s industrial control systems. The Company has broadened the scope and frequency of vulnerability assessments aimed at identification of potentially exposed information systems. The Company also executed a company-wide security education and awareness program in the past year. The Company has a centralized information office which supports the development of standardized systems, use of industry proven packages where feasible, use of an information security risk management strategy and disaster recovery plans for critical operations. Back-up computers are installed in business units for enterprise-wide fail protection. BUSINESS ENVIRONMENT RISKS ABORIGINAL RELATIONS Canadian judicial decisions have recognized that Aboriginal rights and treaty rights exist in proximity to the Company’s operations and future project developments. The courts have also confirmed that the Crown has a duty to consult with Aboriginal peoples when its decisions or actions may adversely affect Aboriginal rights and interests or treaty rights. Crown consultation has the potential to delay regulatory approval processes and construction, which may affect project economics. In some cases, respecting Aboriginal rights may mean regulatory approval is denied or made economically challenging. 86 < ENBRIDGE INC. 2012 FINANCIAL REPORT C O O O A RA PUB D R ER R ORKER A SA A FET R OR R TRA RKE AFE C ACT U ONT AN BL Y TY TO TR WO LIC, O VI PT D R ERR RR R ERV EN C C S U N CE T ENT CI NC I TIO TI TER TE NT I SER S D S R SEC EN TEM C SY C YST U T ENT CI N I Y TY RIT EMS TE YS G O O A LAT B AB R OR A NA REL R A S ONS AL EL TIO ATI GI RIG

Management’s Discussion and Analysis > 87 Given this environment and the breadth of relationships across the Company’s geographic span, Enbridge has implemented the Aboriginal and Native American Policy. This Policy promotes the achievement of participative and mutually beneficial relationships with Aboriginal and Native American groups affected by the Company’s projects and operations. Specifically, the Policy sets out principles governing the Company’s relationships with Aboriginal and Native American peoples and makes commitments to work with Aboriginal peoples and Native Americans so they may realize benefits from the Company’s projects and operations. Notwithstanding the Company’s efforts to this end, the issues are complex and the impact of Aboriginal and Native American relations on Enbridge’s operations and development initiatives is uncertain. SPECIAL INTEREST GROUPS INCLUDING NON-GOVERNMENTAL ORGANIZATIONS The Company is exposed to the risk of higher costs, delays or even project cancellations due to increasing pressure on governments and regulators by special interest groups, including non-governmental organizations. Recent Supreme Court decisions have increased the ability of special interest groups to make claims and oppose projects in regulatory and legal forums. In addition to issues raised by groups focused on particular project impacts, the Company and others in the energy and pipeline businesses are facing opposition from organizations opposed to oil sands development and shipment of production from oil sands regions. The Company works proactively with special interest groups and non-governmental organizations to identify and develop appropriate responses to their concerns regarding its projects. The Company is investing significant resources in these areas. Its CSR program also reports on the Company’s responsiveness to environmental and community issues. Please see Enbridge’s annual CSR Report, available online at csr.enbridge.com for further details regarding the CSR program. None of the information contained on, or connected to, Enbridge’s website is incorporated in or otherwise part of this MD&A. Critical Accounting Estimates DEPRECIATION Depreciation of property, plant and equipment, the Company’s largest asset with a net book value at December 31, 2012 of $33,318 million (2011 – $29,074 million), or 70.6% of total assets, is generally provided on a straight-line basis over the estimated service lives of the assets commencing when the asset is placed in service. When it is determined that the estimated service life of an asset no longer reflects the expected remaining period of benefit, prospective changes are made to the estimated service life. Estimates of useful lives are based on third party engineering studies, experience and/or industry practice. There are a number of assumptions inherent in estimating the service lives of the Company’s assets including the level of development, exploration, drilling, reserves and production of crude oil and natural gas in the supply areas served by the Company’s pipelines as well as the demand for crude oil and natural gas and the integrity of the Company’s systems. Changes in these assumptions could result in adjustments to the estimated service lives, which could result in material changes to depreciation expense in future periods in any of the Company’s business segments. For certain rate-regulated operations, depreciation rates are approved by the regulator and the regulator may require periodic studies or technical updates on useful lives which may change depreciation rates. ASSET IMPAIRMENT The Company evaluates the recoverability of its property, plant and equipment when events or circumstances such as economic obsolescence, business climate, legal or regulatory changes, or other factors indicate it may not recover the carrying amount of the assets. The Company continually monitors its businesses, the market and business environments to identify indicators that could suggest an asset may not be recoverable. An impairment loss is recognized when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of the fair value using present value techniques requires the use of projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes to these projections and assumptions could result in revisions to the evaluation of the recoverability of the property, plant and equipment and the recognition of an impairment loss in the Consolidated Statements of Earnings. EST S O O O OV O A TA PEC P SP PS R OR D S GR R ER R ER M A GA A IA VER RES -G A ZAT C C U LU NO NC VE AL IZA ONS TI ATI IZ AN ENT EN RN ON G NG I CL I T TER TE NT I AL CIA

REGULATORY ASSETS AND LIABILITIES Certain of the Company’s businesses are subject to regulation by various authorities, including but not limited to, the NEB, the FERC, the ERCB and the OEB. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in operations may differ from that otherwise expected under U.S. GAAP for non rate-regulated entities. Also, the Company records regulatory assets and liabilities to recognize the economic effects of the actions of the regulator. Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates. On refund or recovery of this difference, no earnings impact is recorded. As at December 31, 2012, the Company’s significant regulatory assets totaled $1,246 million (2011 – $972 million) and significant regulatory liabilities totaled $882 million (2011 – $836 million). To the extent that the regulator’s actions differ from the Company’s expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. POSTRETIREMENT BENEFITS The Company maintains pension plans, which provide defined benefit and/or defined contribution pension benefits and OPEB to eligible retirees. Pension costs and obligations for the defined benefit pension plans are determined using the universal method. This method involves complex actuarial calculations using several assumptions including discount rates, which were determined by referring to high-quality long-term corporate bonds with maturities that approximate the timing of future payments the Company anticipates making under each of the respective plans, expected rates of return on plan assets, health-care cost trend rates, projected salary increases, retirement age, mortality and termination rates. These assumptions are determined by management and are reviewed annually by the Company’s actuaries. Actual results that differ from assumptions are amortized over future periods and therefore could materially affect the expense recognized and the recorded obligation in future periods. The actual return on plan assets exceeded the expected return on plan assets by $24 million for the year ended December 31, 2012 (2011 – $76 million shortfall) as disclosed in Note 24 to the 2012 Annual Consolidated Financial Statements. The difference between the actual and expected return on plan assets is amortized over the remaining service period of the active employees. The following sensitivity analysis identifies the impact on the December 31, 2012 Consolidated Financial Statements of a 0.5% change in key pension and OPEB assumptions. Pensions Benefits OPEB Obligation Expense Obligation Expense (millions of Canadian dollars) Decrease in discount rate 141 19 21 2 Decrease in expected return on assets – 6 – – Decrease in rate of salary increase (30) (5) – – CONTINGENT LIABILITIES Provisions for claims filed against the Company are determined on a case-by-case basis. Case estimates are reviewed on a regular basis and are updated as new information is received. The process of evaluating claims involves the use of estimates and a high degree of management judgment. Claims outstanding, the final determination of which could have a material impact on the financial results of the Company and certain of the Company’s subsidiaries and investments, including EGD and EECI, are detailed in the Commitments and Contingencies section of this report and are disclosed in Note 28 of the 2012 Annual Consolidated Financial Statements. In addition, any unasserted claims that later may become evident could have a material impact on the financial results of the Company and certain of the Company’s subsidiaries and investments. 88 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 89 ASSET RETIREMENT OBLIGATIONS In May 2009, the NEB released a report on the financial issues associated with pipeline abandonment and established a goal for pipelines regulated under the NEB Act to begin collecting and setting aside funds to cover future abandonment costs no later than January 1, 2015. Since then, the NEB has issued revised “base case assumptions” based on feedback from member companies. Companies have the option to follow the base case assumptions or to submit pipeline specific applications. On November 29, 2011, as required by the NEB, the Company filed its estimated abandonment costs for its regulated pipeline systems within EPI and Enbridge Pipelines (NW) Inc. (Group 1 companies) and Enbridge Southern Lights GP Inc., Enbridge Bakken Pipeline Company Inc., Enbridge Pipelines (Westspur) Inc. and Vector Pipelines Limited Partnership (Group 2 companies). In the fourth quarter of 2012, the NEB held a hearing on the abandonment costs estimates for Group 1 companies with a decision expected in the first quarter of 2013. The NEB also requires regulated pipeline companies file a proposed process and mechanism to set aside the funds for future abandonment costs by February 28, 2013 for Group 1 companies and by May 31, 2013 for Group 2 companies. These costs would be recovered from shippers through tolls in accordance with NEB’s determination that abandonment costs are a legitimate cost of providing services and are recoverable upon NEB approval from users of the system. The NEB requires Group 1 and Group 2 companies to file proposals for collection of the funds in tolls by May 31, 2013. All applications for both Enbridge and EPI will require NEB approval and will result in increased transportation tolls and regulated liabilities. The specific toll impacts are uncertain at this time as the Company anticipates the NEB filings in mid-2013 will go to hearing prior to NEB approval. Currently, for certain of the Company’s assets, there is insufficient data or information to reasonably determine the timing of settlement for estimating the fair value of the asset retirement obligation (ARO). In these cases, the ARO cost is considered indeterminate for accounting purposes, as there is no data or information that can be derived from past practice, industry practice or the estimated economic life of the asset. Changes in Accounting Policies UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES The Company commenced reporting using U.S. GAAP as its primary basis of accounting effective January 1, 2012, including restatement of comparative periods. As a Securities and Exchange Commission (SEC) registrant, the Company is permitted to use U.S. GAAP for purposes of meeting both its Canadian and United States continuous disclosure requirements. To facilitate users’ understanding of the transition to U.S. GAAP, the Company restated its 2011 consolidated financial statements, which were originally prepared in accordance with Part V – Pre-changeover Accounting Standards of the Canadian Institute of Chartered Accountants Handbook, to U.S. GAAP, including full comparative information and related note disclosure. The 2011 U.S. GAAP financial statements were filed with securities regulators in Canada and the United States on May 2, 2012 and are available on SEDAR at www.sedar.com and on the Company’s website at www.enbridge.com. None of the information contained on, or connected to, Enbridge’s website is incorporated or otherwise part of this MD&A.

FAIR VALUE MEASUREMENT Effective January 1, 2012, the Company adopted Accounting Standards Update (ASU) 2011-04, which revised the existing guidance on the disclosure of fair value measurements. Under the revised standard, the Company is required to provide additional disclosures about fair value measurements, including a description of the valuation methodologies used and information about the unobservable inputs and assumptions used in Level 3 fair value measurements, as well as the level in the fair value hierarchy of items that are not measured at fair value but whose fair value disclosure is required. As the adoption of this update impacted disclosure only, there was no impact to the Company’s earnings or cash flows for the current or prior periods presented. STATEMENT OF COMPREHENSIVE INCOME Effective January 1, 2012, the Company adopted ASU 2011-05, which updated existing guidance on comprehensive income, requiring presentation of earnings and OCI either in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive, statements of earnings and OCI. The adoption of this pronouncement did not affect the Company’s presentation of comprehensive income and did not impact the Company’s consolidated financial statements. GOODWILL IMPAIRMENT Effective January 1, 2012, the Company adopted ASU 2011-08 which is intended to reduce the overall costs and complexity of goodwill impairment testing. The standard allows an entity the option to first assess qualitative factors to determine whether it is necessary to perform the current two-step goodwill impairment test. Under this option, an entity is not required to calculate the fair value of a reporting unit unless the entity determines, based on a qualitative assessment, it is more likely than not its fair value is less than its carrying amount. Adoption of this standard does not change the current two-step goodwill impairment test. FUTURE ACCOUNTING POLICY CHANGES BALANCE SHEET OFFSETTING ASU 2011-11 was issued in December 2011 and provides enhanced disclosures on the effect or potential effect of netting arrangements on an entity’s financial position. The adoption of the pronouncement affects financial statement disclosures only and is not anticipated to have a material impact on the Company’s consolidated financial statements. This accounting update is effective for annual and interim periods beginning on or after January 1, 2013. ACCUMULATED OTHER COMPREHENSIVE INCOME ASU 2013-02 was issued in February 2013 and provides enhanced disclosures on amounts reclassified out of AOCI. The adoption of the pronouncement affects financial statement disclosures only and is not anticipated to have a material impact on the Company’s consolidated financial statements. This accounting update is effective for annual and interim periods beginning after December 15, 2012. 90 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Discussion and Analysis > 91 Controls and Procedures DISCLOSURE CONTROLS AND PROCEDURES Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and United States securities law. As at December 31, 2012, an evaluation was carried out under the supervision of and with the participation of Enbridge’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operations of Enbridge’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective in ensuring that information required to be disclosed by Enbridge in reports that it files with or submits to the SEC and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required. MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Management of Enbridge is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in the rules of the SEC and the Canadian Securities Administrators. The Company’s internal control over financial reporting is a process designed under the supervision and with the participation of executive and financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external reporting purposes in accordance with U.S. GAAP. The Company’s internal control over financial reporting includes policies and procedures that: pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets of the Company; provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. The Company’s internal control over financial reporting may not prevent or detect all misstatements because of inherent limitations. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with the Company’s policies and procedures. Management assessed the effectiveness of the Company’s internal control over financial reporting as at December 31, 2012, based on the framework established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Management concluded that the Company maintained effective internal control over financial reporting as at December 31, 2012. During the year ended December 31, 2012, there has been no material change in the Company’s internal control over financial reporting. The effectiveness of the Company’s internal control over financial reporting as at December 31, 2012 has been audited by PricewaterhouseCoopers LLP, independent auditors appointed by the shareholders of the Company.

Non-GAAP Reconciliations 2012 2011 2010 (millions of Canadian dollars) Earnings attributable to common shareholders 610 820 944 Adjusting items: Liquids Pipelines Canadian Mainline – Line 9 tolling adjustment (6) (10) – Canadian Mainline – changes in unrealized derivative fair value (gains)/loss (42) 48 – Canadian Mainline – shipper dispute settlement – (14) – Regional Oil Sands System – prior period adjustment 6 – – Regional Oil Sands System – asset impairment write-off – 8 – Regional Oil Sands System – gain on acquisition – – (20) Spearhead Pipeline – changes in unrealized derivative fair value gains – (1) – Gas Distribution EGD – warmer/(colder) than normal weather 23 (1) 12 EGD – tax rate changes 9 – – EGD – recognition of regulatory asset (63) – – Other Gas Distribution and Storage – regulatory deferral write-off – 262 – Gas Pipelines, Processing and Energy Services Aux Sable – changes in unrealized derivative fair value (gains)/loss (10) 7 (7) Energy Services – changes in unrealized derivative fair value (gains)/loss 537 (125) 8 Energy Services – credit recovery – – (1) Offshore – asset impairment loss 105 – – Offshore – property insurance recovery from hurricanes – – (2) Other – changes in unrealized derivative fair value gains – (24) – Sponsored Investments EEP – leak insurance recoveries (24) (50) – EEP – leak remediation costs and lost revenue 9 33 106 EEP – changes in unrealized derivative fair value (gains)/loss 2 (3) 1 EEP – NGL trucking and marketing investigation costs 1 3 – EEP – prior period adjustment (7) – – EEP – shipper dispute settlement – (8) – EEP – lawsuit settlement – (1) – EEP – impact of unusual weather conditions – 1 – EEP – Lakehead System billing correction – – (1) EEP – asset impairment loss – – 2 Corporate Noverco – equity earnings adjustment 12 – – Noverco – changes in unrealized derivative fair value loss 10 – – Other Corporate – changes in unrealized derivative fair value (gains)/loss 22 87 (25) Other Corporate – foreign tax recovery (29) – – Other Corporate – unrealized foreign exchange (gains)/loss on translation of intercompany balances, net 17 (24) (40) Other Corporate – impact of tax rate changes 11 (6) – Other Corporate – tax on intercompany gain on sale 56 98 – Adjusted earnings 1,249 1,100 977 92 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Management’s Report > 93 MANAGEMENT’S REPORT To the Shareholders of Enbridge Inc. FINANCIAL REPORTING Management of Enbridge Inc. (the Company) is responsible for the accompanying consolidated financial statements. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and necessarily include amounts that reflect management’s judgment and best estimates. The Board of Directors and its committees are responsible for all aspects related to governance of the Company. The Audit, Finance & Risk Committee (AF&RC) of the Board, composed of directors who are unrelated and independent, has a specific responsibility to oversee management’s efforts to fulfil its responsibilities for financial reporting and internal controls related thereto. The AF&RC meets with management, internal auditors and independent auditors to review the consolidated financial statements and the internal controls as they relate to financial reporting. The AF&RC reports its findings to the Board for its consideration in approving the consolidated financial statements for issuance to the shareholders. INTERNAL CONTROL OVER FINANCIAL REPORTING Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting includes policies and procedures to facilitate the preparation of relevant, reliable and timely information, to prepare consolidated financial statements for external reporting purposes in accordance with generally accepted accounting principles and provide reasonable assurance that assets are safeguarded. Management assessed the effectiveness of the Company’s internal control over financial reporting as at December 31, 2012, based on the framework established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as at December 31, 2012. PricewaterhouseCoopers LLP, independent auditors appointed by the shareholders of the Company, conducts an examination of the consolidated financial statements in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). AL MONACO J. RICHARD BIRD President & Chief Executive Officer Executive Vice President & Chief Financial Officer February 14, 2013 S N P R ’ R O A A T E T N E M E G M S f I d i r h n e e e g r r b e t n h h d o o o a c s . E l O P C A R R F A G L N I T E I N N I O O O C N P R A A R R R R G F E O A C N L E L L E I T I N N I V T N N T I

INDEPENDENT AUDITOR’S REPORT To the Shareholders of Enbridge Inc. We have completed an integrated audit of Enbridge Inc.’s 2012 consolidated financial statements and its internal control over financial reporting as at December 31, 2012 and audits of its 2011 and 2010 consolidated financial statements. Our opinions, based on our audits, are presented below. REPORT ON THE CONSOLIDATED FINANCIAL STATEMENTS We have audited the accompanying consolidated financial statements of Enbridge Inc., which comprise the consolidated statements of financial position as at December 31, 2012 and December 31, 2011 and the consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2012, and the related notes, which comprise a summary of significant accounting policies and other explanatory information. MANAGEMENT’S RESPONSIBILITY FOR THE CONSOLIDATED FINANCIAL STATEMENTS Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. AUDITOR’S RESPONSIBILITY Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. Canadian generally accepted auditing standards also require that we comply with ethical requirements. An audit involves performing procedures to obtain audit evidence, on a test basis, about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the company’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting principles and policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion on the consolidated financial statements. OPINION In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Enbridge Inc. as at December 31, 2012 and December 31, 2011 and results of its operations and its cash flows for each of the three years in the period ended December 31, 2012 in accordance with accounting principles generally accepted in the United States of America. REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING We have also audited Enbridge Inc.’s internal control over financial reporting as at December 31, 2012, based on criteria established in Internal Control – Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 94 < ENBRIDGE INC. 2012 FINANCIAL REPORT P D D D P O R R’ R O AU S T E T T N E N E E N I I S f I i h e e n e e r n h h r r g d b d o o o a c s . t E l O O C T P D D O O A TAT A AT R E R F E E A S C S S L L T N E M E AT TA I N N I T I N H T N C O O O O C P B D D R S A A R ’ E E H F F Y A TA A A A S S S S S N M L E E E T N AT T I N N I E AT I L N T T I L I I E T N M G N M O O S U P B D R R’S Y A S N E T I L I I T I O I I P O N N O O P P R R R O C O A A T R R R R G F E O O A C L L E N I T E I N N I V T N L N N I N T E

Independent Auditor’s Report > 95 MANAGEMENT’S RESPONSIBILITY FOR INTERNAL CONTROL OVER FINANCIAL REPORTING Management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying management’s report on internal control over financial reporting. AUDITOR’S RESPONSIBILITY Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control, based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our audit opinion on the company’s internal control over financial reporting. DEFINITION OF INTERNAL CONTROL OVER FINANCIAL REPORTING A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. INHERENT LIMITATIONS Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate. OPINION In our opinion, Enbridge Inc. maintained, in all material respects, effective internal control over financial reporting as at December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by COSO. Chartered Accountants Calgary, Alberta, Canada February 14, 2013 O O O O O S N P P B G S A A R R R R M ’ R R R F F E O Y A A A C C S L E L E E E N I T I N N I V L T N L N T N I T I I I N T N E G M O O D P R B S A R N ’ E Y S S U L T I I I T I C C D P R R O O O O O A A R R R F E F F E O G A L E L L E N I T I N N I V T N N T N I N I T I N I R A TAT E O S L N I AT TA I M I T N E H N I ON N I P O I

CONSOLIDATED STATEMENTS OF EARNINGS Year ended December 31, 2012 2011 2010 (millions of Canadian dollars, except per share amounts) Revenues Commodity sales 19,101 20,611 15,863 Gas distribution sales 1,910 1,906 1,814 Transportation and other services 4,295 4,536 3,843 25,306 27,053 21,520 Expenses Commodity costs 18,566 19,864 15,276 Gas distribution costs 1,220 1,281 1,249 Operating and administrative 2,890 2,281 2,032 Depreciation and amortization 1,206 1,112 1,017 Environmental costs, net of recoveries (Note 28) (88) (116) 619 23,794 24,422 20,193 1,512 2,631 1,327 Income from equity investments (Note 11) 160 210 228 Other income (Note 25) 240 117 318 Interest expense (Note 16) (841) (928) (865) 1,071 2,030 1,008 Income taxes (Note 23) (128) (526) (227) Earnings before extraordinary loss 943 1,504 781 Extraordinary loss, net of tax (Note 5) – (262) – Earnings 943 1,242 781 (Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests (228) (409) 170 Earnings attributable to Enbridge Inc. 715 833 951 Preference share dividends (105) (13) (7) Earnings attributable to Enbridge Inc. common shareholders 610 820 944 Earnings attributable to Enbridge Inc. common shareholders Earnings before extraordinary loss 610 1,082 944 Extraordinary loss, net of tax (Note 5) – (262) – 610 820 944 Earnings per common share attributable to Enbridge Inc. common shareholders (Note 19) Earnings before extraordinary loss 0.79 1.44 1.27 Extraordinary loss, net of tax – (0.35) – 0.79 1.09 1.27 Diluted earnings per common share attributable to Enbridge Inc. common shareholders (Note 19) Earnings before extraordinary loss 0.78 1.42 1.26 Extraordinary loss, net of tax – (0.34) – 0.78 1.08 1.26 The accompanying notes are an integral part of these consolidated financial statements. 96 < ENBRIDGE INC. 2012 FINANCIAL REPORT C O O O D D R A TAT F A AT S S S S E G N N T N E M E AT TA E N I I L

Consolidated FInancial Statements > 97 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Year ended December 31, 2012 2011 2010 (millions of Canadian dollars) Earnings 943 1,242 781 Other comprehensive income/(loss), net of tax Change in unrealized loss on cash flow hedges (176) (582) (156) Change in unrealized gain/(loss) on net investment hedges 13 (19) 51 Other comprehensive income/(loss) from equity investees 2 (17) 4 Reclassification to earnings of realized cash flow hedges 7 14 (15) Reclassification to earnings of unrealized cash flow hedges (Note 22) 20 12 (3) Reclassification to earnings of pension plans and other postretirement benefits amortization amounts 18 21 16 Actuarial loss on pension plans and other postretirement benefits (56) (165) (54) Change in foreign currency translation adjustment (159) 151 (376) Other comprehensive loss (331) (585) (533) Comprehensive income 612 657 248 Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests (164) (329) 331 Comprehensive income attributable to Enbridge Inc. 448 328 579 Preference share dividends (105) (13) (7) Comprehensive income attributable to Enbridge Inc. common shareholders 343 315 572 The accompanying notes are an integral part of these consolidated financial statements. C O O C O O D D R P A TAT M O F AT C N S S S S V E M N E E H E M T N E E AT TA E N I I I L

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY Year ended December 31, 2012 2011 2010 (millions of Canadian dollars, except per share amounts) Preference shares (Note 19) Balance at beginning of year 1,056 125 125 Preference shares issued 2,651 931 – Balance at end of year 3,707 1,056 125 Common shares (Note 19) Balance at beginning of year 3,969 3,683 3,379 Common shares issued 388 – – Dividend reinvestment and share purchase plan 297 229 224 Shares issued on exercise of stock options 78 57 80 Balance at end of year 4,732 3,969 3,683 Additional paid-in capital Balance at beginning of year 242 131 90 Stock-based compensation 26 18 13 Options exercised (17) (7) (8) Issuance of treasury stock (Note 11) 236 – – Dilution gains and other 35 100 36 Balance at end of year 522 242 131 Retained earnings Balance at beginning of year 3,926 3,993 3,828 Earnings attributable to Enbridge Inc. 715 833 951 Preference share dividends (105) (13) (7) Common share dividends declared (895) (759) (648) Dividends paid to reciprocal shareholder 20 25 19 Redemption value adjustment attributable to redeemable noncontrolling interests (Note 18) (197) (153) (150) Balance at end of year 3,464 3,926 3,993 Accumulated other comprehensive loss (Note 21) Balance at beginning of year (1,532) (1,027) (654) Other comprehensive loss attributable to Enbridge Inc. common shareholders (267) (505) (373) Balance at end of year (1,799) (1,532) (1,027) Reciprocal shareholding (Note 11) Balance at beginning of year (187) (154) (154) Issuance of treasury stock 61 – – Acquisition of equity investment – (33) – Balance at end of year (126) (187) (154) Total Enbridge Inc. shareholders’ equity 10,500 7,474 6,751 Noncontrolling interests (Note 18) Balance at beginning of year 3,141 2,424 2,740 Earnings/(loss) attributable to noncontrolling interests 241 416 (182) Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax Change in unrealized loss on cash flow hedges (39) (84) (12) Change in foreign currency translation adjustment (60) 66 (121) Reclassification to earnings/(loss) of realized cash flow hedges 23 (63) (13) Reclassification to earnings/(loss) of unrealized cash flow hedges 13 4 (2) (63) (77) (148) Comprehensive income/(loss) attributable to noncontrolling interests 178 339 (330) Distributions (Note 18) (421) (355) (318) Contributions (Note 18) 382 735 358 Dilution gains 6 22 15 Acquisitions (Note 6) (25) (27) (41) Other (3) 3 – Balance at end of year 3,258 3,141 2,424 Total equity 13,758 10,615 9,175 Dividends paid per common share 1.13 0.98 0.85 The accompanying notes are an integral part of these consolidated financial statements. 98 < ENBRIDGE INC. 2012 FINANCIAL REPORT S C O TA D D S S S O O Q H F E Y G C A A TAT AT U E T E N E N T N M AT E N I I I L

Consolidated FInancial Statements > 99 CONSOLIDATED STATEMENTS OF CASH FLOWS Year ended December 31, 2012 2011 2010 (millions of Canadian dollars) Operating activities Earnings 943 1,242 781 Depreciation and amortization 1,206 1,112 1,017 Deferred income taxes (recovery)/expense (Note 23) (40) 368 203 Changes in unrealized (gains)/loss on derivative instruments, net 665 (73) – Cash distributions in excess of equity earnings 474 125 102 Regulatory asset write-off (Note 5) – 262 – Gain on acquisition (Note 6) – – (22) Asset impairment (Note 9) 166 11 11 Allowance for equity funds used during construction (1) (3) (96) Other 110 14 9 Changes in regulatory assets and liabilities 37 28 29 Changes in environmental liabilities, net of recoveries (Note 28) (26) (118) 267 Changes in operating assets and liabilities (Note 26) (660) 403 (424) 2,874 3,371 1,877 Investing activities Additions to property, plant and equipment (5,468) (3,508) (3,053) Long-term investments (531) (1,515) (35) Additions to intangible assets (163) (154) (56) Acquisitions, net of cash acquired (Note 6) (340) (33) (850) Affiliate loans, net 8 7 14 Proceeds on sale of investments and net assets 18 – 23 Government grant – 145 – Changes in restricted cash (2) (2) (5) Changes in construction payable 274 (19) 60 (6,204) (5,079) (3,902) Financing activities Net change in bank indebtedness and short-term borrowings 412 224 (165) Net change in commercial paper and credit facility draws (294) (630) (212) Net change in Southern Lights project financing (13) (62) 14 Debenture and term note issues 2,199 1,604 3,220 Debenture and term note repayments (349) (234) (631) Repayment of acquired debt (160) – – Contributions from noncontrolling interests 448 873 439 Distributions to noncontrolling interests (421) (355) (318) Contributions from redeemable noncontrolling interests 213 210 – Distributions to redeemable noncontrolling interests (49) (35) (23) Preference shares issued 2,634 926 – Common shares issued 465 46 66 Preference share dividends (93) (7) (7) Common share dividends (597) (530) (426) 4,395 2,030 1,957 Effect of translation of foreign denominated cash and cash equivalents (12) 25 (12) Increase/(decrease) in cash and cash equivalents 1,053 347 (80) Cash and cash equivalents at beginning of year 723 376 456 Cash and cash equivalents at end of year 1,776 723 376 Supplementary cash flow information Income taxes (received)/paid 267 (28) 115 Interest paid 988 955 871 The accompanying notes are an integral part of these consolidated financial statements. O C O E D D S S A TAT C O O H F F E A AT S S S L W T N M AT TA E N I L

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION December 31, 2012 2011 (millions of Canadian dollars; number of shares in millions) Assets Current assets Cash and cash equivalents 1,776 723 Restricted cash 19 17 Accounts receivable and other (Note 7) 4,014 4,029 Accounts receivable from affiliates 12 55 Inventory (Note 8) 779 823 6,600 5,647 Property, plant and equipment, net (Note 9) 33,318 29,074 Long-term investments (Note 11) 3,386 3,081 Deferred amounts and other assets (Note 12) 2,622 2,500 Intangible assets, net (Note 13) 817 711 Goodwill (Note 14) 419 440 Deferred income taxes (Note 23) 10 41 47,172 41,494 Liabilities and equity Current liabilities Bank indebtedness 479 102 Short-term borrowings (Note 16) 583 548 Accounts payable and other (Note 15) 5,052 4,753 Accounts payable to affiliates – 48 Interest payable 196 185 Environmental liabilities (Note 28) 107 175 Current maturities of long-term debt (Note 16) 652 354 7,069 6,165 Long-term debt (Note 16) 20,203 19,251 Other long-term liabilities (Note 17) 2,541 2,208 Deferred income taxes (Note 23) 2,601 2,615 32,414 30,239 Commitments and contingencies (Note 28) Redeemable noncontrolling interests (Note 18) 1,000 640 Equity Share capital (Note 19) Preference shares 3,707 1,056 Common shares (805 and 781 outstanding at December 31, 2012 and 2011, respectively) 4,732 3,969 Additional paid-in capital 522 242 Retained earnings 3,464 3,926 Accumulated other comprehensive loss (Note 21) (1,799) (1,532) Reciprocal shareholding (Note 11) (126) (187) Total Enbridge Inc. shareholders’ equity 10,500 7,474 Noncontrolling interests (Note 18) 3,258 3,141 13,758 10,615 47,172 41,494 The accompanying notes are an integral part of these consolidated financial statements. Approved by the Board of Directors: DAVID A. ARLEDGE, Chair DAVID A. LESLIE, Director 100 < ENBRIDGE INC. 2012 FINANCIAL REPORT O O C O O O C S D D P S E F F A A A TAT AT S S E N T N N T N M AT TA E N I I L I I I L

Notes to the Consolidated Financial Statements > 101 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 1. General Business Description Enbridge Inc. (Enbridge or the Company) is a publicly traded energy transportation and distribution company. Enbridge conducts its business through five business segments: Liquids Pipelines; Gas Distribution; Gas Pipelines, Processing and Energy Services; Sponsored Investments and Corporate. These operating segments are strategic business units established by senior management to facilitate the achievement of the Company’s long-term objectives, to aid in resource allocation decisions and to assess operational performance. LIQUIDS PIPELINES Liquids Pipelines consists of common carrier and contract crude oil, natural gas liquids (NGL) and refined products pipelines and terminals in Canada and the United States, including the Canadian Mainline, Regional Oil Sands System, Southern Lights Pipeline, Seaway Pipeline, Spearhead Pipeline, Feeder Pipelines and Other. GAS DISTRIBUTION Gas Distribution consists of the Company’s natural gas utility operations, the core of which is Enbridge Gas Distribution Inc. (EGD) which serves residential, commercial and industrial customers, primarily in central and eastern Ontario as well as northern New York State. This business segment also includes natural gas distribution activities in Quebec and New Brunswick. GAS PIPELINES, PROCESSING AND ENERGY SERVICES Gas Pipelines, Processing and Energy Services consists of investments in natural gas pipelines and processing and gathering facilities and the Company’s energy services businesses, along with renewable energy projects. Investments in natural gas pipelines include the Company’s interests in the United States portion of the Alliance System (Alliance Pipeline US), the Vector Pipeline (Vector) and transmission and gathering pipelines in the Gulf of Mexico. Investments in natural gas processing include the Company’s interest in Aux Sable, a natural gas fractionation and extraction business located at the terminus of the Alliance System. The energy services businesses undertake physical commodity marketing activity and manage the Company’s volume commitments on the Alliance System, the Vector Pipeline and other pipeline systems. SPONSORED INVESTMENTS Sponsored Investments includes the Company’s 21.8% (2011 – 23.0%) ownership interest in Enbridge Energy Partners, L.P. (EEP), Enbridge’s 66.7% (2011 – 66.7%) investment in the United States segment of the Alberta Clipper Project through EEP and Enbridge Energy, Limited Partnership and an overall 67.7% (2011 – 69.2%) economic interest in Enbridge Income Fund (the Fund), held both directly and indirectly through Enbridge Income Fund Holdings Inc. (ENF). Enbridge manages the day-to-day operations of, and develops and assesses opportunities for each of these investments, including both organic growth and acquisition opportunities. EEP transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines and transports, gathers, processes and markets natural gas and NGL. The primary operations of the Fund include renewable power generation projects, crude oil and liquids pipeline and storage businesses in Western Canada and a 50% interest in the Canadian portion of the Alliance System (Alliance Pipeline Canada). CORPORATE Corporate consists of the Company’s investment in Noverco Inc. (Noverco), new business development activities, general corporate investments and financing costs not allocated to the business segments. O O O D D S O F C A TAT A A AT C N S S S L T N E M E AT TA N E N E H T T E T N I I I L i B D i i n s 1 r o r n u n p e e e e c t a s s s l G . QU I P P D ES S E N I L I I L G B D R S O AS U N I T I T I S A P E P P D S R ER RO G G Y A C C S S S S L E E E I V G N E N N I E N I I , O S S P D O M S S R E E T N T V N I E N O P AT

2. Summary of Significant Accounting Policies These consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP). Amounts are stated in Canadian dollars unless otherwise noted. The Company commenced reporting using U.S. GAAP as its primary basis of accounting effective January 1, 2012, including restatement of comparative periods. As a Securities and Exchange Commission registrant, the Company is permitted to use U.S. GAAP for purposes of meeting both its Canadian and United States continuous disclosure requirements. BASIS OF PRESENTATION AND USE OF ESTIMATES The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities in the consolidated financial statements. Significant estimates and assumptions used in the preparation of the consolidated financial statements include, but are not limited to: carrying values of regulatory assets and liabilities (Note 5); unbilled revenues (Note 7); allowance for doubtful accounts (Note 7); depreciation rates and carrying value of property, plant and equipment (Note 9); amortization rates of intangible assets (Note 13); measurement of goodwill (Note 14); valuation of stock-based compensation (Note 20); fair value of financial instruments (Note 22); provisions for income taxes (Note 23); assumptions used to measure retirement and other postretirement benefit obligations (OPEB) (Note 24); commitments and contingencies (Note 28); fair value of asset retirement obligations (ARO); and estimates of losses related to environmental remediation obligations (Note 28). Actual results could differ from these estimates. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of Enbridge, its subsidiaries and a variable interest entity (VIE) for which the Company is the primary beneficiary. The consolidated financial statements also include the accounts of any limited partnerships where the Company represents the general partner and, based on all facts and circumstances, controls such limited partnerships. All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to noncontrolling interests and redeemable noncontrolling interests. Investments and entities over which the Company exercises significant influence are accounted for using the equity method. REGULATION Certain of the Company’s businesses are subject to regulation by various authorities including, but not limited to, the National Energy Board (NEB), the Federal Energy Regulatory Commission (FERC), the Energy Resources Conservation Board in Alberta, the New Brunswick Energy and Utilities Board (EUB), and the Ontario Energy Board (OEB). Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under U.S. GAAP for non rate-regulated entities. 102 < ENBRIDGE INC. 2012 FINANCIAL REPORT i i i P t f S A i i i n e m m o o c c g g o n n n r a S a s c c . t u l f u 2 y S O O E P B D O S A F R F E AT A A TAT S S U S S N M E I T E E N I AT TA N I S S O C F L P I P D O R O O A C N L E N I AT I N I O AT R G U N I L E

Notes to the Consolidated Financial Statements > 103 Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates. Long-term regulatory assets are recorded in Deferred amounts and other assets and current regulatory assets are recorded in Accounts receivable and other. Long-term regulatory liabilities are included in Other long-term liabilities and current regulatory liabilities are recorded in Accounts payable and other. Regulatory assets are assessed for impairment if the Company identifies an event indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions of the regulator. To the extent that the regulator’s actions differ from the Company’s expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, the Company would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. Allowance for funds used during construction (AFUDC) is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component which are both capitalized based on rates set out in a regulatory agreement. In the absence of rate regulation, the Company would capitalize interest using a capitalization rate based on its cost of borrowing and the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation would not be recognized. Certain regulators prescribe the pool method of accounting for property, plant and equipment where similar assets with comparable useful lives are grouped and depreciated as a pool. When those assets are retired or otherwise disposed of, gains and losses are not reflected in earnings but are booked as an adjustment to accumulated depreciation. Entities not subject to rate regulation write off the net book value of the retired asset and include any resulting gain or loss in earnings. With the approval of the regulator, EGD and certain distribution operations capitalize a percentage of certain operating costs. These operations are authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years. To the extent that the regulator’s actions differ from the Company’s expectations, the timing and amount of recovery or settlement of capitalized costs could differ significantly from those recorded. In the absence of rate regulation, a portion of such costs may be charged to current period earnings. REVENUE RECOGNITION For businesses which are not rate-regulated, revenues are recorded when products have been delivered or services have been performed, the amount of revenue can be reliably measured and collectability is reasonably assured. Customer credit worthiness is assessed prior to agreement signing as well as throughout the contract duration. Certain Liquids Pipelines revenues are recognized under the terms of committed delivery contracts rather than the cash tolls received. For rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying agreements as approved by the regulators. From July 1, 2011 onward, Canadian Mainline (excluding Lines 8 and 9) earnings are governed by the Competitive Toll Settlement (CTS), under which revenues are recorded when services are performed. Effective on that date, the Company prospectively discontinued the application of rate-regulated accounting for those assets with the exception of flow-through income taxes covered by a specific rate order. For natural gas utility rate-regulated operations in Gas Distribution, revenue is recognized in a manner consistent with the underlying rate-setting mechanism as mandated by the regulator. Natural gas utilities revenues are recorded on the basis of regular meter readings and estimates of customer usage from the last meter reading to the end of the reporting period. Estimates are based on historical consumption patterns and heating degree days experienced. Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in the Company’s distribution franchise area. For natural gas and marketing businesses, an estimate of revenues and commodity costs for the month of December is included in the Consolidated Statements of Earnings for each year based on the best available volume and price data for the commodity delivered and received. O O R R C U E E N I T I N G E N E V

DERIVATIVE INSTRUMENTS AND HEDGING NON-QUALIFYING DERIVATIVES Non-qualifying derivative instruments are used primarily to economically hedge foreign exchange, interest rate and commodity price earnings exposure. Non-qualifying derivatives are measured at fair value with changes in fair value recognized in earnings in Transportation and other services revenues, Commodity costs, Operating and administrative expense, Other income and Interest expense. DERIVATIVES IN QUALIFYING HEDGING RELATIONSHIPS The Company uses derivative financial instruments to manage changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to its share price. Hedge accounting is optional and requires the Company to document the hedging relationship and test the hedging item’s effectiveness in offsetting changes in fair values or cash flows of the underlying hedged item on an ongoing basis. The Company presents the earnings effects of hedging items with the hedged transaction. Derivatives in qualifying hedging relationships are categorized as cash flow hedges, fair value hedges and net investment hedges. CASH FLOW HEDGES The Company uses cash flow hedges to manage changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to its share price. The effective portion of the change in the fair value of a cash flow hedging instrument is recorded in Other comprehensive income/(loss) (OCI) and is reclassified to earnings when the hedged item impacts earnings. Any hedge ineffectiveness is recorded in current period earnings. If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is discontinued and the gain or loss at that date is deferred in OCI and recognized concurrently with the related transaction. If a hedged anticipated transaction is no longer probable, the gain or loss is recognized immediately in earnings. Subsequent gains and losses from derivative instruments for which hedge accounting has been discontinued are recognized in earnings in the period in which they occur. FAIR VALUE HEDGES The Company may use fair value hedges to hedge the fair value of debt instruments or commodity positions. The change in the fair value of the hedging instrument is recorded in earnings with changes in the fair value of the hedged asset or liability that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be effective, the hedged asset or liability, otherwise required to be carried at cost or amortized cost, ceases to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the hedged item is recognized in earnings over the remaining life of the hedged item. The Company did not have any fair value hedges at December 31, 2012 or 2011. NET INVESTMENT HEDGES The Company uses net investment hedges to manage the carrying values of United States dollar denominated foreign operations. The effective portion of the change in the fair value of the hedging instrument is recorded in OCI. Any ineffectiveness is recorded in current period earnings. Amounts recorded in Accumulated other comprehensive income/(loss) (AOCI) are recognized in earnings when there is a reduction of the hedged net investment resulting from a disposal of the foreign operation. 104 < ENBRIDGE INC. 2012 FINANCIAL REPORT D D D S AN R R E G G AT A S U VE N I E H T N E M T N I I V I Q ES O D R ER E G F - A VA V A UA U VE V L TI T I N YI Y I N N O PS S D ED D R ER R A VAT VES FY G G A LAT A UA ES Q NG VE VA I SH NS TIO ATI EL REL G GI H N YI LI AL N I TIV ATI RIV

Notes to the Consolidated Financial Statements > 105 CLASSIFICATION OF DERIVATIVES The Company recognizes the fair market value of derivative instruments on the Consolidated Statements of Financial Position as current and long-term assets or liabilities depending on the timing of the settlements and the resulting cash flows associated with the instruments. Fair value amounts related to cash flows occurring beyond one year are classified as non-current. Cash inflows and outflows related to derivative instruments are classified as Operating activities on the Consolidated Statements of Cash Flows. BALANCE SHEET OFFSET Assets and liabilities arising from derivative instruments are offset in the Consolidated Statements of Financial Position when the Company has the legal right and intention to settle them on a net basis. TRANSACTION COSTS Transaction costs are incremental costs directly related to the acquisition of a financial asset or the issuance of a financial liability. The Company incurs transaction costs primarily through the issuance of debt and classifies these costs with Deferred amounts and other assets. These costs are amortized using the effective interest rate method over the life of the related debt instrument. EQUITY INVESTMENTS Equity investments over which the Company exercises significant influence, but does not have controlling financial interests, are accounted for using the equity method. Equity investments are initially measured at cost and are adjusted for the Company’s proportionate share of undistributed equity earnings or loss. Equity investments are increased for contributions made to and decreased for distributions received from the investees. To the extent an equity investee undertakes activities necessary to commence its planned principal operations, the Company capitalizes interest costs associated with its investment during such period. OTHER INVESTMENTS Generally, the Company classifies equity investments in entities over which it does not exercise significant influence and that do not trade on an actively quoted market as other investments carried at cost. Financial assets in this category are initially recorded at fair value with no subsequent re-measurement. Any investments which do trade on an active market are measured at fair value through OCI. Dividends received from these financial assets are recognized in earnings when the right to receive payment is established. NONCONTROLLING INTERESTS Noncontrolling interests represent the outstanding ownership interests attributable to third parties in certain consolidated subsidiaries, limited partnerships and VIEs. The portion of equity in entities not owned by the Company is reflected as noncontrolling interests within the equity section of the Consolidated Statements of Financial Position and, in the case of redeemable noncontrolling interests, within the mezzanine section of the Consolidated Statements of Financial Position between long-term liabilities and equity. The Fund’s noncontrolling interest holders have the option to redeem the Fund trust units for cash, subject to certain limitations. Redeemable noncontrolling interests are recognized at the maximum redemption value of the trust units held by third parties, which references the market price of ENF common shares. On a quarterly basis, changes in estimated redemption values are reflected as a charge or credit to retained earnings. O S O TI T D S CA C R E F FI F A V A AS C VE V L VA E I TI T I ER N I O FS S BA EET EE SET FFS OFF A LA C T T SH CE ANC AL O O ANS TS C SA R TRA TI A A RA ST ACT ON TR S M N Y S U Q N E T E T V I T I E R M S O S T N E T E V N I E H T S O O S O R ERE C G L T T N I N I L T N N N

INCOME TAXES The liability method of accounting for income taxes is followed. Deferred income tax assets and liabilities are recorded based on temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes. Deferred income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse. For the Company’s regulated operations, a deferred income tax liability is recognized along with a corresponding regulatory asset. Any interest and/or penalty incurred related to tax is reflected in Income taxes. FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which the Company or a reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date. Exchange gains and losses resulting from translation of monetary assets and liabilities are included in the Consolidated Statements of Earnings in the period that they arise. Gains and losses arising from translation of foreign operations’ functional currencies to the Company’s Canadian dollar presentation currency are included in the cumulative translation adjustment component of AOCI and are recognized in earnings upon sale of the foreign operation. Asset and liability accounts are translated at the exchange rates in effect on the balance sheet date, while revenues and expenses are translated using monthly average exchange rates. CASH AND CASH EQUIVALENTS Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased. RESTRICTED CASH Cash and cash equivalents that are restricted, in accordance with specific customer agreements, as to withdrawal or usage are presented as Restricted cash on the Consolidated Statements of Financial Position. LOANS AND RECEIVABLES Affiliate long-term notes receivable are measured at amortized cost using the effective interest rate method, net of any impairment losses recognized. Accounts receivable and other are measured at cost. ALLOWANCE FOR DOUBTFUL ACCOUNTS The allowance for doubtful accounts is determined based on collection history. When the Company has determined that further collection efforts are unlikely to be successful, amounts charged to the allowance for doubtful accounts are applied against the impaired accounts receivable. INVENTORY Inventory is comprised of natural gas in storage held in EGD and crude oil and natural gas held primarily by energy services businesses. Natural gas in storage in EGD is recorded at the quarterly prices approved by the OEB in the determination of distribution rates. The actual price of gas purchased may differ from the OEB approved price. The difference between the approved price and the actual cost of the gas purchased is deferred as a liability for future refund or as an asset for collection as approved by the OEB. Other commodities inventory is recorded at the lower of cost, as determined on a weighted average basis, or market value. Upon disposition, other commodities inventory is recorded to Commodity costs in the Consolidated Statements of Earnings at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value. 106 < ENBRIDGE INC. 2012 FINANCIAL REPORT C S A TAX E O E TA M N I O O C C S S R D AT A A A T R R R R F O Y A C S U L E N I N T N N I N T N E N G I S S D A A H E E A A C C S U Q L T N V I N H C S D R R A C S E H T I T E O C S B D A A R E A S N V L E L I E N O C R B D O A T W F F E O O A A C S C U U U L L L N T N ORY VE T N N I

Notes to the Consolidated Financial Statements > 107 PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is recorded at historical cost. Expenditures for construction, expansion, major renewals and betterments are capitalized. Maintenance and repair costs are expensed as incurred. Expenditures for project development are capitalized if they are expected to have future benefit. The Company capitalizes interest incurred during construction for non rate-regulated assets. For rate-regulated assets, AFUDC is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component. For non rate-regulated assets depreciation is provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in service. DEFERRED AMOUNTS AND OTHER ASSETS Deferred amounts and other assets primarily include: costs which regulatory authorities have permitted, or are expected to permit, to be recovered through future rates including deferred income taxes; contractual receivables under the terms of long-term delivery contracts; derivative financial instruments; and deferred financing costs. Deferred financing costs are amortized using the effective interest method over the term of the related debt. INTANGIBLE ASSETS Intangible assets consist primarily of acquired long-term transportation or power purchase agreements, natural gas supply opportunities and certain software costs. Natural gas supply opportunities are growth opportunities, identified upon acquisition, present in gas producing zones where certain of EEP’s gas systems are located. The Company capitalizes costs incurred during the application development stage of internal use software projects. Intangible assets are amortized on a straight-line basis over their expected lives, commencing when the asset is available for use. GOODWILL Goodwill represents the excess of the purchase price over the fair value of net identifiable assets on acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually, or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. For the purposes of impairment testing, reporting units are identified as business operations within an operating segment. The Company has the option to first assess qualitative factors to determine whether it is necessary to perform the two-step goodwill impairment test. If the two-step goodwill impairment test is performed, potential impairment is identified when the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value. Goodwill impairment is measured as the excess of the carrying amount of the reporting unit’s allocated goodwill over the implied fair value of the goodwill based on the fair value of the assets and liabilities of the reporting unit. IMPAIRMENT The Company reviews the carrying values of its long-lived assets as events or changes in circumstances warrant. If it is determined that the carrying value of an asset exceeds the undiscounted cash flows expected from the asset, the asset is written down to fair value. With respect to investments in debt and equity securities, the Company assesses at each balance sheet date whether there is objective evidence that a financial asset is impaired by completing a quantitative or qualitative analysis of factors impacting the investment. If there is determined to be objective evidence of impairment, the Company internally values the expected discounted cash flows using observable market inputs and determines whether the decline below carrying value is other than temporary. If the decline is determined to be other than temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the asset. R P P P P D T R E E O Y A A U Q L T N M I N T N E , O O S S S D E F D D R R A R S E A A U M E T E E H T N T N B A TA E A S S S N ET L I G N I D O O W L L I G P R A E T N M I M I

With respect to other financial assets, the Company assesses the assets for impairment when it no longer has reasonable assurance of timely collection. If evidence of impairment is noted, the Company reduces the value of the financial asset to its estimated realizable amount, determined using discounted expected future cash flows. ASSET RETIREMENT OBLIGATIONS ARO associated with the retirement of long-lived assets are measured at fair value and recognized as Other long-term liabilities in the period in which they can be reasonably determined. The fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. ARO are added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. The Company’s estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements. For the majority of the Company’s assets, it is not possible to make a reasonable estimate of ARO due to the indeterminate timing and scope of the asset retirements. RETIREMENT AND POSTRETIREMENT BENEFITS The Company maintains pension plans which provide defined benefit and defined contribution pension benefits. Defined benefit pension plan costs are determined using actuarial methods and are funded through contributions determined using the projected benefit method, which incorporates management’s best estimate of future salary levels, other cost escalations, retirement ages of employees and other actuarial factors including discount rates. The Company determines discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate the timing of future payments the Company anticipates making under each of the respective plans. During the year ended December 31, 2012, the Company refined the methodology by which it determines discount rates, in particular, refining the method by which it estimates spreads for bonds with longer term maturities. Pension cost is charged to earnings and includes: Cost of pension plan benefits provided in exchange for employee services rendered during the year; Amortization of the prior service costs and amendments on a straight-line basis over the expected average remaining service period of the active employee group covered by the plans; Interest cost of pension plan obligations; Expected return on pension fund assets; and Amortization of cumulative unrecognized net actuarial gains and losses in excess of 10% of the greater of the accrued benefit obligation or the fair value of plan assets, over the expected average remaining service life of the active employee group covered by the plans. Actuarial gains and losses arise from the difference between the actual and expected rate of return on plan assets for that period or from changes in actuarial assumptions used to determine the accrued benefit obligation, including discount rate, changes in headcount or salary inflation experience. Pension plan assets are measured at fair value. The expected return on pension plan assets is determined using market related values and assumptions on the specific invested asset mix within the pension plans. The market related values reflect estimated return on investments consistent with long-term historical averages for similar assets. For defined contribution plans, contributions made by the Company are expensed in the period in which the contribution occurs. The Company also provides OPEB other than pensions, including group health care and life insurance benefits for eligible retirees, their spouses and qualified dependents. The cost of such benefits is accrued during the years in which employees render service. 108 < ENBRIDGE INC. 2012 FINANCIAL REPORT O OB G S AT T R S R E A S M L E N I I T N E E I T OS P B D R E E R R R F A S N E T I E N E T N E M E I T T T N M E I T

Notes to the Consolidated Financial Statements > 109 The overfunded or underfunded status of defined benefit pension and OPEB plans is recognized as Deferred amounts and other assets or Other long-term liabilities on the Consolidated Statements of Financial Position. A plan’s funded status is measured as the difference between the fair value of plan assets and the plan’s projected benefit obligation. Any unrecognized actuarial gains and losses and prior service costs and credits that arise during the period are recognized as a component of OCI, net of tax. Certain regulated utility operations of the Company expect to recover pension expense in future rates and therefore record a corresponding regulatory asset to the extent such recovery is deemed to be probable. For years prior to 2012 an offsetting regulatory asset related to OPEB obligations was not recorded given recovery in rates was not probable. Commencing in 2012, pursuant to a specific rate order allowing for recovery in rates of OPEB costs determined on an accrual basis, an offsetting OPEB regulatory asset was recognized. In the absence of rate regulation, regulatory balances would not be recorded and pension and OPEB costs would be charged to earnings on an accrual basis. STOCK-BASED COMPENSATION Incentive Stock Options (ISOs) granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value of the ISOs granted as calculated by the Black-Scholes- Merton model and is recognized on a straight-line basis over the shorter of the vesting period or the period to early retirement eligibility, with a corresponding credit to Additional paid-in capital. Balances in Additional paid-in capital are transferred to Share capital when the options are exercised. Performance based stock options (PBSOs) granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value of the PBSOs granted as calculated by the Bloomberg barrier option valuation model and is recognized over the vesting period with a corresponding credit to Additional paid-in capital. The options become exercisable when both performance targets and time vesting requirements have been met. Balances in Additional paid-in capital are transferred to Share capital when the options are exercised. Performance Stock Units (PSUs) and Restricted Stock Units (RSUs) are cash settled awards for which the related liability is remeasured each reporting period. PSUs vest at the completion of a three-year term and RSUs vest at the completion of a 35-month term. During the vesting term, an expense is recorded based on the number of units outstanding and the current market price of the Company’s shares with an offset to Accounts payable and other or Other long-term liabilities. The value of the PSUs is also dependent on the Company’s performance relative to performance targets set out under the plan. COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES The Company expenses or capitalizes, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. The Company expenses costs incurred for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. The Company records liabilities for environmental matters when assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. The Company’s estimates are subject to revision in future periods based on actual costs or new information and are included in Environmental liabilities and Other long-term liabilities in the Consolidated Statements of Financial Position at their undiscounted amounts. There is always a potential of incurring additional costs in connection with environmental liabilities due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies, in addition to fines and penalties, as well as expenditures associated with litigation and settlement of claims. The Company evaluates recoveries from insurance coverage separately from the liability and, when recovery is probable, the Company records and reports an asset separately from the associated liability in the Consolidated Statements of Financial Position. O O O S S S D B P A T - AT C C E E N I N M K C O O C C B D S S A A TA A E RO S M L E E E E E I T I I I L L T N N I V N N I N G N I T N T N M T I M M ,

Liabilities for other commitments and contingencies are recognized when, after fully analyzing available information, the Company determines it is either probable that an asset has been impaired, or that a liability has been incurred, and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, the Company recognizes the most likely amount, or if no amount is more likely than another, the minimum of the range of probable loss is accrued. The Company expenses legal costs associated with loss contingencies as such costs are incurred. 3. Changes in Accounting Policies FAIR VALUE MEASUREMENT Effective January 1, 2012, the Company adopted Accounting Standards Update (ASU) 2011-04, which revised the existing guidance on the disclosure of fair value measurements. Under the revised standard, the Company is required to provide additional disclosures about fair value measurements, including a description of the valuation methodologies used and information about the unobservable inputs and assumptions used in Level 3 fair value measurements, as well as the level in the fair value hierarchy of items that are not measured at fair value but whose fair value disclosure is required. As the adoption of this update impacted disclosure only, there was no impact to the Company’s earnings or cash flows for the current or prior periods presented. STATEMENT OF COMPREHENSIVE INCOME Effective January 1, 2012, the Company adopted ASU 2011-05, which updates the existing guidance on comprehensive income, requiring presentation of earnings and OCI either in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive, statements of earnings and OCI. The adoption of this pronouncement did not affect the Company’s presentation of comprehensive income and did not impact the Company’s consolidated financial statements. GOODWILL IMPAIRMENT Effective January 1, 2012, the Company adopted ASU 2011-08 which is intended to reduce the overall costs and complexity of goodwill impairment testing. The standard allows an entity the option to first assess qualitative factors to determine whether it is necessary to perform the current two-step goodwill impairment test. Under this option, an entity is not required to calculate the fair value of a reporting unit unless the entity determines, based on a qualitative assessment, it is more likely than not its fair value is less than its carrying amount. Adoption of this standard does not change the current two-step goodwill impairment test. FUTURE ACCOUNTING POLICY CHANGES BALANCE SHEET OFFSETTING ASU 2011-11 was issued in December 2011 and provides enhanced disclosures on the effect or potential effect of netting arrangements on an entity’s financial position. The adoption of the pronouncement affects financial statement disclosures only and is not anticipated to have a material impact on the Company’s consolidated financial statements. This accounting update is effective for annual and interim periods beginning on or after January 1, 2013. ACCUMULATED OTHER COMPREHENSIVE INCOME ASU 2013-02 was issued in February 2013 and provides enhanced disclosures on amounts reclassified out of AOCI. The adoption of the pronouncement affects financial statement disclosures only and is not anticipated to have a material impact on the Company’s consolidated financial statements. This accounting update is effective for annual and interim periods beginning after December 15, 2012. 110 < ENBRIDGE INC. 2012 FINANCIAL REPORT P i A i C i i n n n h s s o g ge e n 3 o c c a c t l u . R S A F R A A U U E E T N M E M E L V I O PR S S A TAT M E F O O C C N E E E M N I E V I E H T N M AT TA O P D O R A M L E L T N I M I I W G C C E P C O O A A R E F G Y C S U U U G L N H I N I T N T O FS BA FFS FF G A LA A C S NG TI TT SET T EET EE SH CE ANC AL O O C C O P D ED R ER A LAT S REH TED R PR AC C U U NC E VE L M I SIV ENS EN EH M TH ATE M

Notes to the Consolidated Financial Statements > 111 4. Segmented Information Year ended December 31, 2012 Liquids Pipelines 1 Gas Distribution Gas Pipelines, Processing and Energy Services 1 Sponsored Investments 1 Corporate 2 Consolidated (millions of Canadian dollars) Revenues 2,452 2,438 13,745 6,671 – 25,306 Commodity and gas distribution costs – (1,220) (14,283) (4,283) – (19,786) Operating and administrative (943) (528) (289) (1,076) (54) (2,890) Depreciation and amortization (363) (336) (62) (431) (14) (1,206) Environmental costs, net of recoveries – – – 88 – 88 1,146 354 (889) 969 (68) 1,512 Income/(loss) from equity investments 46 – 108 53 (47) 160 Other income/(expense) (7) 83 30 49 85 240 Interest income/(expense) (250) (164) (51) (397) 21 (841) Income taxes recovery/(expense) (205) (66) 325 (169) (13) (128) Earnings/(loss) 730 207 (477) 505 (22) 943 Earnings attributable to noncontrolling interests and redeemable noncontrolling interests (4) – (1) (223) – (228) Preference share dividends – – – – (105) (105) Earnings/(loss) attributable to Enbridge Inc. common shareholders 726 207 (478) 282 (127) 610 Additions to property, plant and equipment 3 2,092 438 837 1,993 109 5,469 Total assets 15,252 7,416 5,119 15,780 3,605 47,172 Year ended December 31, 2011 Liquids Pipelines 1 Gas Distribution Gas Pipelines, Processing and Energy Services 1 Sponsored Investments 1 Corporate 2 Consolidated (millions of Canadian dollars) Revenues 1,942 2,516 13,599 8,996 – 27,053 Commodity and gas distribution costs – (1,282) (13,051) (6,812) – (21,145) Operating and administrative (752) (508) (138) (847) (36) (2,281) Depreciation and amortization (322) (320) (75) (383) (12) (1,112) Environmental costs, net of recoveries – – – 116 – 116 868 406 335 1,070 (48) 2,631 Income/(loss) from equity investments 5 – 153 57 (5) 210 Other income/(expense) 31 (12) 40 68 (10) 117 Interest expense (256) (166) (56) (350) (100) (928) Income taxes recovery/(expense) (140) (54) (166) (171) 5 (526) Earnings/(loss) before extraordinary loss 508 174 306 674 (158) 1,504 Extraordinary loss, net of tax – (262) – – – (262) Earnings/(loss) 508 (88) 306 674 (158) 1,242 Earnings attributable to noncontrolling interests and redeemable noncontrolling interests (3) – (1) (405) – (409) Preference share dividends – – – – (13) (13) Earnings/(loss) attributable to Enbridge Inc. common shareholders 505 (88) 305 269 (171) 820 Additions to property, plant and equipment 3 958 483 850 1,187 33 3,511 Total assets 12,348 7,189 4,468 13,492 3,997 41,494 i n n m n m d o e e e a r t f g 4 o S ti I .

Year ended December 31, 2010 Liquids Pipelines 1 Gas Distribution Gas Pipelines, Processing and Energy Services 1 Sponsored Investments 1 Corporate 2 Consolidated (millions of Canadian dollars) Revenues 1,627 2,484 9,604 7,805 – 21,520 Commodity and gas distribution costs – (1,249) (9,386) (5,890) – (16,525) Operating and administrative (579) (508) (105) (807) (33) (2,032) Depreciation and amortization (303) (310) (55) (339) (10) (1,017) Environmental costs – – – (619) – (619) 745 417 58 150 (43) 1,327 Income from equity investments 9 – 151 59 9 228 Other income/(expense) 139 (17) 28 36 132 318 Interest expense (224) (179) (51) (280) (131) (865) Income taxes recovery/(expense) (136) (66) (61) (44) 80 (227) Earnings/(loss) 533 155 125 (79) 47 781 (Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests (2) (5) – 177 – 170 Preference share dividends – – – – (7) (7) Earnings attributable to Enbridge Inc. common shareholders 531 150 125 98 40 944 Additions to property, plant and equipment 3 764 387 1,114 884 – 3,149 1 In December 2012 and October 2011, certain crude oil storage and renewable energy assets were transferred to the Fund within the Sponsored Investments segment. Earnings from the assets prior to the date of transfer of $33 million (2011 – $71 million; 2010 – $42 million) have not been reclassified among segments for presentation purposes. 2 Included within the Corporate segment was Interest income of $336 million (2011 – $239 million; 2010 – $188 million) charged to other operating segments. 3 Includes allowance for equity funds used during construction. The measurement basis for preparation of segmented information is consistent with the significant accounting policies (Note 2). GEOGRAPHIC INFORMATION REVENUES 1 Year ended December 31, 2012 2011 2010 (millions of Canadian dollars) Canada 12,171 12,097 9,385 United States 13,135 14,956 12,135 25,306 27,053 21,520 1 Revenues are based on the country of origin of the product or service sold. PROPERTY, PLANT AND EQUIPMENT December 31, 2012 2011 (millions of Canadian dollars) Canada 19,293 16,690 United States 14,025 12,384 33,318 29,074 112 < ENBRIDGE INC. 2012 FINANCIAL REPORT O I P A R R F E O O G AT C N M I N I H G R ES U REVE EN VEN O P P P OP P D R ERT R PR A LA Y,

Notes to the Consolidated Financial Statements > 113 5. Financial Statement Effects of Rate Regulation GENERAL INFORMATION ON RATE REGULATION AND ITS ECONOMIC EFFECTS A number of businesses within the Company are subject to regulation. The Company’s significant regulated businesses and related accounting impacts are described below. CANADIAN MAINLINE The Canadian Mainline includes the Canadian portion of the mainline system and is subject to regulation by the NEB. Canadian Mainline tolls (excluding Lines 8 and 9) are currently governed by the CTS and do not attract rate-regulated accounting with the exception of flow-through income taxes covered by a specific rate order. Prior to July 1, 2011, the effective date of the CTS, the Incentive Tolling Settlement (ITS) defined the methodology for calculation of tolls on the core component of Canadian Mainline and was recorded in accordance with rateregulated accounting guidance. Toll adjustments for variances from requirements defined in the ITS were filed annually with the regulator for approval. Surcharges were also determined for a number of system expansion components and were added to the base toll determined for the core system. Upon transition to the CTS on July 1, 2011 and the discontinuance of rate-regulated accounting at that time, a regulatory asset of approximately $470 million continued to be recognized as a NEB rate order governing flow-through income tax treatment permits future recovery. SOUTHERN LIGHTS The United States portion of the Southern Lights Pipeline is regulated by the FERC and the Canadian portion of the pipeline is regulated by the NEB. Shippers on the Southern Lights Pipeline are subject to 15-year transportation contracts, which expire in 2025, under a cost of service toll methodology. Toll adjustments are filed annually with the regulators. Tariffs provide for recovery of all operating and debt financing costs, plus a pre-determined after-tax rate of return on equity of 10%. Southern Lights Pipeline tolls are based on a deemed 70% debt and 30% equity structure. ENBRIDGE GAS DISTRIBUTION EGD’s gas distribution operations are regulated by the OEB. For the years ended December 31, 2012, 2011 and 2010, EGD’s annual rates were set based on a revenue per customer cap incentive regulation methodology which adjusted revenues, and consequently rates, annually and relied on an annual process to forecast volume and customer additions. EGD’s after-tax rate of return on common equity embedded in rates was 8.4% for the years ended December 31, 2012, 2011 and 2010 based on a 36% deemed common equity component of capital for regulatory purposes for each of those years. In November 2012, EGD received a rate order from the OEB permitting recovery of OPEB costs in the amount of $89 million ($63 million after-tax). The amount will be collected in rates over a 20-year period commencing in 2013. The gain is presented within Other income on the Consolidated Statements of Earnings. The rate order further provides for future OPEB costs, determined on an accrual basis, to be recovered in rates. ENBRIDGE GAS NEW BRUNSWICK Enbridge Gas New Brunswick (EGNB) is regulated by the EUB. As at December 31, 2011, EGNB discontinued rate-regulated accounting due to amendments in the rate setting methodology enacted by the Government of New Brunswick, and consequently wrote-off a deferred regulatory asset of $180 million and a regulatory asset with respect to capitalized operating costs of $103 million, net of an income tax recovery of $21 million. The write-off of $262 million, net of tax, was presented as an extraordinary loss on the Consolidated Statements of Earnings for the year ended December 31, 2011. f S R i i i n n s n m e a o o e t e e e t f n R E F a a a g a 5 c c u t t l f t t l . O S G D O O O C R R R R F F E F E O O A A A A A C C S U G M L E E E E L E T I N T I N N I AT AT N N I AT M N I N A MA A IA D AD A NA A CA L E N LI N AI AN ANA O R ER S UT TS G L HT LIG RN TH AS GA O R BR B B D D STR TR G A UT EN N TIO TI RI IS GE RI AS D B EN

FINANCIAL STATEMENT EFFECTS Accounting for rate-regulated activities has resulted in the recognition of the following significant regulatory assets and liabilities: December 31, 2012 2011 (millions of Canadian dollars) Regulatory assets/(liabilities) Liquids Pipelines Deferred income taxes 1 605 527 Deferred transportation revenues 2 155 84 Gas Distribution Deferred income taxes 3 201 170 Future removal and site restoration reserves 4 (882) (836) Pension plans and OPEB 5 212 108 Sponsored Investments Deferred income taxes 3 73 83 1 The asset represents the regulatory offset to deferred income tax liabilities that are expected to be recovered under flow-through income tax treatment. The recovery period depends on future temporary differences. 2 Deferred transportation revenues are related to the cumulative difference between U.S. GAAP depreciation expense for Southern Lights and the negotiated depreciation rates included in the regulated transportation tolls. The Company expects to recover this difference after 2020 when depreciation rates in the transportation agreements are expected to exceed U.S. GAAP depreciation rates. 3 The asset represents the regulatory offset to deferred income tax liabilities to the extent that deferred income taxes are expected to be included in regulator-approved future rates and recovered from or refunded to future customers. The recovery period depends on future temporary differences. 4 The future removal and site restoration reserves balance results from amounts collected from customers by certain businesses, with the approval of the regulator, to fund future costs for removal and site restoration relating to property, plant and equipment. These costs are collected as part of depreciation charged on property, plant and equipment. The balance represents the amount that has been collected from customers, net of actual costs expended on removal and site restoration. The settlement of this balance will occur as future removal and site restoration costs are incurred. 5 The pension plans and OPEB balances represent the regulatory offset to pension plan and OPEB obligations to the extent the amounts are expected to be collected from customers in future rates. An OPEB balance of $89 million is expected to be collected on a straight-line basis over a 20-year period commencing in 2013, whereas the settlement period for the pension regulatory asset is not determinable. OTHER ITEMS AFFECTED BY RATE REGULATION ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION AND OTHER CAPITALIZED COSTS Under the pool method prescribed by certain regulators, it is not possible to identify the carrying value of the equity component of AFUDC or its effect on depreciation. Similarly, gains or losses on the retirement of certain specific fixed assets in any given year cannot be identified or quantified. OPERATING COST CAPITALIZATION With the approval of regulators, certain operations capitalize a percentage of certain operating costs. These operations are authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years. In the absence of rate regulation, a portion of such operating costs would be charged to earnings in the year incurred. EGD entered into a consulting contract relating to asset management initiatives. The majority of the costs, primarily consulting fees, are being capitalized to gas mains in accordance with regulatory approval. At December 31, 2012, cumulative costs relating to this consulting contract of $144 million (2011 – $133 million) were included in property, plant and equipment and are being depreciated over the average service life of 25 years. In the absence of rate regulation, some of these costs would be charged to earnings in the year incurred. 114 < ENBRIDGE INC. 2012 FINANCIAL REPORT C A F F F AT A A C S S M L T E E T N E E T TA T I N N I B D O C AT R F R R E F O G Y AT A U S E E N I L E E T M T I E H T O O O C ST ST TS S O CT O O D P AP D D ED D D ED R ER R R OR ZE IZE A TA A A WA G R TR FU FO A CA A C C UC U US ON N N AL LIZ PIT TH AN TIO TI ONS RI SED CE AN LL AL O O O ATI P AP P CA R ERA PER A A RAT ST A ZAT A TA C N IZATIO ATI LIZ AL PIT T G NG TI

Notes to the Consolidated Financial Statements > 115 6. Acquisitions ACQUISITIONS SILVER STATE NORTH SOLAR PROJECT On March 22, 2012, Enbridge acquired a 100% interest in the Silver State North Solar Project (Silver State), a solar farm located in Nevada for cash consideration of $195 million (US$190 million). Silver State expands the Company’s renewable energy business. Revenues and earnings of $10 million and $1 million, respectively, were recognized in the year ended December 31, 2012. No revenues or earnings were recognized in any prior period as the solar project commenced operations in the second quarter of 2012. Silver State is included within the Gas Pipelines, Processing and Energy Services segment. March 22, 2012 (millions of Canadian dollars) Fair value of net assets acquired: Accounts receivable and other 1 54 Property, plant and equipment 141 195 Purchase price: Cash 195 1 The Company acquired the right to apply for a $54 million (US$55 million) United States Treasury grant under a program which reimburses eligible applicants for a portion of costs related to installing specified renewable energy property. The grant, which was applied for subsequent to commercial operations, was received in October 2012. TONBRIDGE POWER INC. On October 13, 2011, Enbridge acquired 100% of the 36 million outstanding common shares of Tonbridge Power Inc. (Tonbridge), an independent company engaged in constructing an electric transmission line between Montana and Alberta, for $20 million in cash at a price of $0.54 per share. Tonbridge is included within the Corporate segment. October 13, 2011 (millions of Canadian dollars) Fair value of net assets acquired: Working capital deficiency (5) Property, plant and equipment 196 Intangible assets 17 Long-term debt (182) Other long-term liabilities (21) 5 Purchase price: Cash (net of $15 million cash acquired) 5 No revenues from Tonbridge were recognized in 2011 as the transmission line was not in service. A net loss of $1 million was recognized in earnings for the period from October 13, 2011 to December 31, 2011 related to operating and administrative expense. An unaudited proforma net loss of $38 million, including $6 million of transaction costs, would have been recognized in earnings in 2011 had the acquisition occurred on January 1, 2011. i A i i n s 6 s o q c ti u . Q C O A S S U N I T I I O O S O PR R VE V R E A T R ER H T E T A C S S J LVE T E L TH N TE TA I O O B PO D R ER R BR C G WER C. NC I WE E RI N TO

ELK CITY NATURAL GAS GATHERING AND PROCESSING SYSTEM On September 16, 2010, EEP acquired a 100% ownership interest in entities that comprise the Elk City Natural Gas Gathering and Processing System (Elk City System) for $705 million (US$686 million). The results of operations of Elk City System have been included within the Sponsored Investments segment from the date of acquisition. September 16, 2010 (millions of Canadian dollars) Fair value of net assets acquired: Current assets 4 Property, plant and equipment 503 Intangible assets 1 194 Other assets 5 Other long-term liabilities (1) 705 Purchase price: Cash 705 1 Intangible assets acquired are natural gas supply opportunities, which are being amortized on a straight line basis over the weighted average estimated useful life of the underlying reserves at the time of acquisition, which approximate 25 to 30 years. OTHER ACQUISITIONS In November 2012, Enbridge acquired certain sour gas gathering and compression facilities for a purchase price of $118 million. These facilities, which are currently in service or under construction, are located in the Peace River Arch region of northwest Alberta and are presented within the Gas Pipelines, Processing and Energy Services segment. As at December 31, 2012, the allocation of consideration paid to the assets was not complete as the Company had not yet concluded its valuation. In May 2012, Enbridge acquired the remaining 10% interest in the Greenwich Wind Energy Project (Greenwich) through Greenwich Windfarm, LP, for cash consideration of $27 million, increasing its ownership interest to 100%. The Company’s interest in Greenwich was consolidated and presented within the Gas Pipelines, Processing and Energy Services segment until such time as it was transferred to the Fund in December 2012 (Note 18). In October 2011, the Company acquired the remaining 10% interest in Talbot Windfarm, LP (Talbot) for $28 million, increasing its ownership interest to 100%. The Company’s interest in Talbot was consolidated and presented within the Gas Pipelines, Processing and Energy Services segment until such time as it was transferred to the Fund in October 2011. In August 2010, the Company acquired an additional 20% interest in Olympic Pipe Line Company (Olympic), a refined products pipeline, for $12 million, increasing its ownership interest to 85%. As the Company now controlled the entity, it consolidated its interest in Olympic. Prior to August 2010, the entity was accounted for as a joint venture using the equity method. 116 < ENBRIDGE INC. 2012 FINANCIAL REPORT GA G GA G S O S K P D R YS Y R E TU T R ER E G G A A A A RA A NA N ES C C S N N EL E EM E TE T I N I TH T L Y T I S O Q O R ER S AC U NS TIO TI SIT IS TH

Notes to the Consolidated Financial Statements > 117 In June 2010, the Company acquired the remaining 50% interest in Hardisty Caverns Limited Partnership (Hardisty Caverns), an oil storage facility, for $52 million, increasing its ownership interest to 100%. The original equity interest and noncontrolling interests were re-measured to fair value on the date control was obtained and a $22 million gain was recorded in Other income (Note 25) for the year ended December 31, 2010. During the year ended December 31, 2010, the Company acquired the remaining 27.5% of EGNB limited partnership units held by third parties for $52 million, increasing its partnership interest to 100%. Other acquisitions during 2010 totaled $29 million (US$27 million) and are included within the Sponsored Investments segment. Unaudited proforma consolidated revenues and earnings that give effect to all of the Company’s other acquisitions as if they had occurred as of January 1 in the year of acquisition are not presented as the information would not be materially different from the information presented in the accompanying Consolidated Statements of Earnings. 7. Accounts Receivable and Other December 31, 2012 2011 (millions of Canadian dollars) Unbilled revenues 2,289 2,210 Trade receivables 677 802 Taxes receivable 123 157 Regulatory assets – 42 Short-term portion of derivative assets (Note 22) 383 486 Prepaid expenses and deposits 132 54 Current deferred income taxes (Note 23) 167 135 Dividends receivable 26 30 Other 266 171 Allowance for doubtful accounts (49) (58) 4,014 4,029 8. Inventory December 31, 2012 2011 (millions of Canadian dollars) Natural gas 448 566 Other commodities 331 257 779 823 Commodity costs on the Consolidated Statements of Earnings included non-cash charges of $10 million (2011 – $9 million; 2010 – $9 million) for the year ended December 31, 2012 to reduce the cost basis of inventory to market value. O h R 7 i n nd b e e c r e e c a A o s a c . t v l t u n n o v 8 e r . t I y

9. Property, Plant and Equipment December 31, Weighted Average Depreciation Rate 2012 2011 (millions of Canadian dollars) Liquids Pipelines Pipeline 2.6% 8,249 7,538 Pumping equipment, buildings, tanks and other 1 3.1% 5,094 5,017 Land and right-of-way 2.4% 225 232 Under construction – 1,675 1,111 15,243 13,898 Accumulated depreciation (3,432) (3,170) 11,811 10,728 Gas Distribution Gas mains, services and other 4.3% 7,583 6,846 Land and right-of-way 2.5% 79 79 Under construction – 102 137 7,764 7,062 Accumulated depreciation (1,912) (1,419) 5,852 5,643 Gas Pipelines, Processing and Energy Services Pipeline 4.6% 544 568 Wind turbines, solar panels and other 1 4.9% 519 781 Land and right-of-way 4.9% 6 7 Under construction – 1,477 512 2,546 1,868 Accumulated depreciation (350) (213) 2,196 1,655 Sponsored Investments Pipeline 3.0% 6,890 6,600 Pumping equipment, buildings, tanks and other 1 3.3% 4,787 3,792 Wind turbines, solar panels and other 1 4.0% 1,544 1,074 Land and right-of-way 2.4% 642 611 Under construction – 2,002 913 15,865 12,990 Accumulated depreciation (2,770) (2,213) 13,095 10,777 Corporate Other 9.4% 105 71 Under construction – 296 230 401 301 Accumulated depreciation (37) (30) 364 271 33,318 29,074 1 In December 2012, wholly-owned subsidiaries of Enbridge sold two crude oil storage and three renewable energy assets to the Fund. As a result, at December 31, 2012, $599 million and $338 million of Property, plant and equipment were reclassified from Liquids Pipelines and Gas Pipelines, Processing and Energy Services, respectively, to Sponsored Investments. The December 31, 2011 balances of $600 million and $354 million, in Liquids Pipelines and Gas Pipelines, Processing and Energy Services, respectively, have not been reclassified for presentation purposes. Depreciation expense for the year ended December 31, 2012 was $1,174 million (2011 – $1,089 million; 2010 – $987 million). 118 < ENBRIDGE INC. 2012 FINANCIAL REPORT P P i n n n p r r d m t e e p 9 Eq o a a u . t t l , y

Notes to the Consolidated Financial Statements > 119 GAS PIPELINES, PROCESSING AND ENERGY SERVICES In December 2012, the Company recorded an impairment charge of $166 million ($105 million after-tax) related to certain of its Enbridge Offshore Pipelines (Offshore) assets, predominantly located within the Stingray and Garden Banks corridors in the Gulf of Mexico. The Company had been pursuing alternative uses for these assets; however, due to changing competitive conditions in the fourth quarter of 2012, the Company concluded that such alternatives were no longer likely to proceed. In addition, unique to these assets is their significant reliance on natural gas production from shallow water areas of the Gulf of Mexico which have been challenged by macro-economic factors including prevalence of onshore shale gas production, hurricane disruptions, additional regulation and the low natural gas commodity price environment. The impairment charge was based on the amount by which the carrying values of the assets exceeded fair value, determined using expected discounted future cash flows, and is presented within Operating and administrative expense on the Consolidated Statements of Earnings. The charge is inclusive of $50 million related to abandonment costs now reasonably determined given the expected timing and scope of certain asset retirements. 10. Variable Interest Entity The Fund is an unincorporated open-ended trust established by a trust indenture under the laws of the Province of Alberta and is considered a VIE by virtue of its capital structure. The Company is the primary beneficiary of the Fund through its combined 67.7% (2011 – 69.2%; 2010 – 72%) economic interest, held indirectly through a common investment in ENF, a direct common trust unit investment in the Fund and a preferred unit investment in a whollyowned subsidiary of the Fund. Enbridge also serves in the capacity of Manager of ENF, the Fund and its subsidiaries. The summarized impact of the Company’s interest in the Fund on earnings, cash flows and financial position is presented below. Earnings include the results of operations of certain assets acquired by the Fund from wholly-owned subsidiaries of Enbridge from the dates of acquisition of October 2011 and December 2012 (Note 18). Earnings, cash flows and financial position information exclude the effect of intercompany transactions. Year ended December 31, 2012 2011 2010 (millions of Canadian dollars) Revenues 288 146 89 Operating and administrative expense (83) (66) (52) Depreciation and amortization (87) (47) (19) Income from equity investments 52 60 60 Interest expense and other (68) (32) (13) Income taxes (35) (21) (17) Earnings 67 40 48 (Earnings)/loss attributable to noncontrolling interest 13 7 (11) Earnings attributable to Enbridge 80 47 37 Cash flows Cash provided by operating activities 198 140 29 Cash used in investing activities (158) (98) (107) Cash provided by financing activities 1,495 381 85 Increase in cash and cash equivalents 1,535 423 7 C S S P P P D SER R R E E O G G Y A A C S S S N N NE L I V G E E N I I E I , i 0 i a r n r e e e t t t t n b a s E I l V . 1 y

December 31, 2012 2011 (millions of Canadian dollars) Current assets 224 109 Property, plant and equipment, net 2,390 1,349 Long-term investments 314 343 Deferred amounts and other assets 179 125 Current liabilities (250) (90) Long-term debt (1,864) (675) Other long-term liabilities (22) (36) Deferred income taxes (438) (403) Net assets before noncontrolling interests 533 722 11. Long-Term Investments December 31, Ownership Interest 2012 2011 (millions of Canadian dollars) Equity Investments Joint Ventures Liquids Pipelines Chicap Pipeline 43.8% 27 27 Mustang Pipeline 30.0% 21 27 Seaway Pipeline 50.0% 1,385 1,186 Gas Pipelines, Processing and Energy Services Offshore – various joint ventures 22.0% – 74.3% 391 420 Vector 60.0% 142 160 Alliance Pipeline US 50.0% 282 293 Aux Sable 1 42.7% – 50.0% 266 217 Other 33.3% – 70.0% 10 21 Sponsored Investments Alliance Pipeline Canada 50.0% 277 296 Texas Express Pipeline 35.0% 183 11 Other 50.0% 35 47 Other Equity Investments Corporate Noverco Common Shares 38.9% – – Other 8.9% – 41.0% 55 34 Other Long-Term Investments Corporate Noverco Preferred Shares 246 285 Other 66 57 3,386 3,081 1 In July 2011, the Company, through its affiliate Aux Sable, acquired a 42.7% interest in the Palermo Conditioning Plant and the Prairie Rose Pipeline for $76 million. Equity investments include the unamortized excess of the purchase price over the underlying net book value of the investees’ assets at the purchase date which is comprised of $636 million (2011 – $651 million) in Goodwill and $493 million (2011 – $450 million) in amortizable assets. 120 < ENBRIDGE INC. 2012 FINANCIAL REPORT I L r n n n 1 e e o e Te m m - g s s t t v . 1

Notes to the Consolidated Financial Statements > 121 JOINT VENTURES Summarized combined financial information of the Company’s interest in unconsolidated equity investments of joint ventures is as follows: Year ended December 31, 2012 2011 2010 (millions of Canadian dollars) Revenues 921 804 771 Commodity costs (236) (138) (92) Operating and administrative expense (244) (200) (203) Depreciation and amortization (159) (158) (158) Other expense 4 (3) (1) Interest expense (81) (87) (96) Earnings before income taxes 205 218 221 December 31, 2012 2011 (millions of Canadian dollars) Current assets 299 231 Property, plant and equipment, net 3,192 2,864 Deferred amounts and other assets 204 273 Intangible assets 74 87 Goodwill 639 651 Current liabilities (333) (230) Long-term debt (895) (926) Other long-term liabilities (161) (245) Net assets 3,019 2,705 ALLIANCE PIPELINE Certain assets of Alliance Pipeline Canada are pledged as collateral to Alliance Pipeline Canada lenders and to the lenders of Alliance Pipeline US. As well, certain assets of Alliance Pipeline US are pledged as collateral to Alliance Pipeline US lenders and to the lenders of Alliance Pipeline Canada. OTHER EQUITY INVESTMENTS NOVERCO At December 31, 2012, Enbridge owned an equity interest in Noverco through ownership of 38.9% (2011 – 38.9%; 2010 – 32.1%) of its common shares and an investment in preferred shares. The preferred shares are entitled to a cumulative preferred dividend based on the average yield of Government of Canada bonds maturing in 10 years plus a range of 4.3% to 4.4%. At December 31, 2011, Noverco owned an approximate 8.9% reciprocal shareholding in the Common Shares of the Company. During the year ended December 31, 2012, Noverco sold 22.5 million Enbridge Common Shares through a secondary offering, thereby reducing the Company’s reciprocal shareholding to 6.0%. Both the Company’s equity investment in Noverco and Equity increased by $297 million, net of tax, as a result of this transaction. The Company’s share of the proceeds of approximately $317 million was received as a dividend from Noverco in May 2012. As a result of Noverco’s 6.0% (2011 – 8.9%; 2010 – 9.0%) reciprocal shareholding in Enbridge shares, the Company has an indirect pro-rata interest of 2.1% (2011 – 3.5%) in its own shares. Both the equity investment in Noverco and shareholders’ equity have been reduced by the reciprocal shareholding of $126 million at December 31, 2012 (2011 – $187 million; 2010 – $154 million). Noverco records dividends paid by the Company as dividend income and the Company eliminates these dividends from its equity earnings of Noverco. The Company records its pro-rata share of dividends paid by the Company to Noverco as a reduction of dividends paid and an increase in the Company’s investment in Noverco. O T S RE J U V T N E N I C P P A IA AL E N LI EL PEL PI CE AN LIA LL R M Y O S S U Q T N E T E V N I T I E E H T OV O VER ERC N

12. Deferred Amounts and Other Assets December 31, 2012 2011 (millions of Canadian dollars) Regulatory assets 1,284 1,000 Long-term portion of derivative assets (Note 22) 408 562 Affiliate long-term note receivable (Note 27) 182 194 Contractual receivables 303 288 Deferred financing costs 127 132 Other 318 324 2,622 2,500 At December 31, 2012, deferred amounts of $265 million (2011 – $255 million) were subject to amortization and are presented net of accumulated amortization of $123 million (2011 – $106 million). Amortization expense for the year ended December 31, 2012 was $25 million (2011 – $20 million; 2010 – $20 million). 13. Intangible Assets December 31, 2012 Weighted Average Amortization Rate Cost Accumulated Amortization Net (millions of Canadian dollars) Software 11.9% 622 180 442 Natural gas supply opportunities 3.8% 291 50 241 Power purchase agreements 4.7% 85 4 81 Transportation agreements 2.9% 50 13 37 Other 5.6% 20 4 16 1,068 251 817 December 31, 2011 Weighted Average Amortization Rate Cost Accumulated Amortization Net (millions of Canadian dollars) Software 12.7% 471 155 316 Natural gas supply opportunities 3.6% 296 39 257 Power purchase agreements 4.6% 78 2 76 Transportation agreements 2.9% 53 10 43 Other 6.0% 27 8 19 925 214 711 Total amortization expense for intangible assets was $64 million (2011 – $58 million; 2010 – $52 million) for the year ended December 31, 2012. The Company expects aggregate amortization expense for the years ending December 31, 2013 through 2017 of $67 million, $61 million, $55 million, $49 million and $44 million, respectively. 122 < ENBRIDGE INC. 2012 FINANCIAL REPORT O d D A 2 s h s s d o re e e e e m n r r f n A s a . t t t u 1 i A n s e e n g b 3 a s s t t l I . 1

Notes to the Consolidated Financial Statements > 123 14. Goodwill Liquids Pipelines Gas Distribution Gas Pipelines, Processing and Energy Services Sponsored Investments Corporate Consolidated (millions of Canadian dollars) Balance at January 1, 2011 47 – 29 355 – 431 Foreign exchange and other 1 – 1 7 – 9 Balance at December 31, 2011 48 – 30 362 – 440 Transfer of assets to the Fund (29) – – 29 – – Foreign exchange and other 3 – (17) (7) – (21) Balance at December 31, 2012 22 – 13 384 – 419 The Company did not recognize any goodwill impairments for the years ended December 31, 2012 and 2011. 15. Accounts Payable and Other December 31, 2012 2011 (millions of Canadian dollars) Operating accrued liabilities 2,729 2,751 Trade payables 123 176 Construction payables 568 327 Current derivative liabilities (Note 22) 1,075 880 Contractor holdbacks 86 46 Taxes payable 206 339 Security deposits 69 81 Current deferred income taxes (Note 23) – 7 Other 196 146 5,052 4,753 l i 1 o w d 4 o . l G O d P h b e n c a e s n r t a A o 5 a c t l u . 1 y

16. Debt December 31, Weighted Average Interest Rate Maturity 2012 2011 (millions of Canadian dollars) Liquids Pipelines Debentures 8.2% 2024 200 200 Medium-term notes 4.9% 2015 – 2112 2,435 2,435 Southern Lights project financing 1 2.7% 2014 1,413 1,449 Commercial paper and credit facility draws 25 26 Other 2 12 13 Gas Distribution Debentures 9.9% 2024 85 85 Medium-term notes 5.5% 2014 – 2050 2,295 2,295 Commercial paper and credit facility draws 590 556 Sponsored Investments Junior subordinated notes 3 8.1% 2067 398 406 Medium-term notes 3.8% 2013 – 2023 1,615 415 Senior notes 4 6.2% 2013 – 2040 4,129 4,322 Commercial paper and credit facility draws 5 1,405 540 Corporate United States dollar term notes 6 5.5% 2014 – 2017 1,094 1,119 Medium-term notes 4.5% 2013 – 2042 4,268 3,518 Commercial paper and credit facility draws 7 1,488 2,785 Other 8 (14) (11) Total debt 21,438 20,153 Current maturities (652) (354) Short-term borrowings 9 (583) (548) Long-term debt 20,203 19,251 1 2012 – $357 million and US$1,061 million (2011 – $360 million and US$1,071 million). 2 Primarily capital lease obligations. 3 2012 – US$400 million (2011 – US$400 million). 4 2012 – US$4,150 million (2011 – US$4,250 million). 5 2012 – $250 million and US$1,160 million (2011 – $260 million and US$275 million). 6 2012 – US$1,100 million (2011 – US$1,100 million). 7 2012 – $1,140 million and US$350 million (2011 – $1,655 million and US$1,111 million). 8 Primarily debt discount. 9 Weighted average interest rate – 1.1% (2011 – 1.1%). For the years ending December 31, 2013 through 2017, debenture and term note maturities are $649 million, $1,287 million, $908 million, $998 million, $1,321 million, respectively, and $11,356 million thereafter. The Company’s debentures and term notes bear interest at fixed rates and interest obligations for the years ending December 31, 2013 through 2017 are $997 million, $976 million, $926 million, $901 million and $826 million, respectively. At December 31, 2012 and 2011, all debt is unsecured except for the Southern Lights project financing which is collateralized by the Southern Lights project assets. 124 < ENBRIDGE INC. 2012 FINANCIAL REPORT D 6 b e t . 1

Notes to the Consolidated Financial Statements > 125 INTEREST EXPENSE Year ended December 31, 2012 2011 2010 (millions of Canadian dollars) Debentures and term notes 986 891 835 Commercial paper and credit facility draws 33 74 66 Southern Lights project financing 38 38 37 Capitalized (216) (75) (73) 841 928 865 CREDIT FACILITIES December 31, 2012 Maturity Dates 1 Total Facilities Draws 2 Available (millions of Canadian dollars) Liquids Pipelines 2014 300 25 275 Gas Distribution 2014 712 590 122 Sponsored Investments 2014 – 2017 3,162 1,645 1,517 Corporate 2014 – 2017 9,108 1,520 7,588 13,282 3,780 9,502 Southern Lights project financing 3 2014 1,484 1,429 55 Total credit facilities 14,766 5,209 9,557 1 Total facilities include $35 million in demand facilities with no maturity date. 2 Includes credit facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility. 3 Total facilities inclusive of $60 million for debt service reserve letters of credit. Credit facilities carry a weighted average standby fee of 0.2% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and the Company has the option to extend the facilities, which are currently set to mature from 2014 to 2017. Commercial paper and credit facility draws, net of short-term borrowings, of $2,925 million (2011 – $3,359 million) are supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt. 17. Other Long-Term Liabilities December 31, 2012 2011 (millions of Canadian dollars) Future removal and site restoration liabilities (Note 5) 882 836 Derivative liabilities (Note 22) 763 557 Pension and OPEB liabilities (Note 24) 573 515 Other 323 300 2,541 2,208 S P R S E X N E E E T E T N I C D R F E AC S L E I T I I T I O 7 i i i i n m e o g e e Te h r r - ab s t L L t l . 1

18. Noncontrolling Interests December 31, 2012 2011 (millions of Canadian dollars) EEP 2,636 2,528 Enbridge Energy Management, L.L.C. (EEM) 498 464 EGD preferred shares 100 100 Greenwich (Note 6) – 26 Other 24 23 3,258 3,141 Noncontrolling interests in EEP represent the 78.2% interest in EEP not owned by the Company. During the year ended December 31, 2012, EEP completed a listed share issuance, in which the Company did not participate, resulting in an increase in the noncontrolling interests from 77.0% to 78.2%. The listed share issuance during the year ended December 31, 2012 resulted in contributions of $382 million (2011 – $695 million; 2010 – $330 million) from noncontrolling interest holders. During the year ended December 31, 2012, EEP also distributed $419 million (2011 – $353 million; 2010 – $311 million) to its noncontrolling interest holders in line with EEP’s objective to make quarterly distributions in an amount equal to its available cash, as defined in its partnership agreement and as approved by EEP’s Board of Directors. Noncontrolling interests in EEM represent the 83.2% of the listed shares of EEM not held by the Company. A listed share issuance during the year ended December 31, 2011 resulted in contributions of $26 million from noncontrolling interest holders. The Company owns 100% of the outstanding common shares of EGD; however, the four million Cumulative Redeemable EGD Preferred Shares held by third parties are entitled to a claim on the assets of EGD prior to the common shareholder. The preferred shares have no fixed maturity date and have floating adjustable cash dividends that are payable at 80% of the prime rate. EGD may, at its option, redeem all or a portion of the outstanding shares for $25 per share plus all accrued and unpaid dividends to the redemption date. As at December 31, 2012, no preferred shares have been redeemed. REDEEMABLE NONCONTROLLING INTERESTS Year ended December 31, 2012 2011 2010 (millions of Canadian dollars) Balance at beginning of year 640 362 236 Earnings/(loss) (13) (7) 12 Other comprehensive loss Change in unrealized loss on cash flow hedges, net of tax (1) (3) (13) Comprehensive loss (14) (10) (1) Distributions to unitholders (49) (33) (23) Contributions from unitholders 226 168 – Redemption value adjustment 197 153 150 Balance at end of year 1,000 640 362 Redeemable noncontrolling interests in the Fund at December 31, 2012 represented 67.7% (2011 – 64.6%; 2010 – 58.2%) of interests in the Fund’s trust units that are held by third parties. 126 < ENBRIDGE INC. 2012 FINANCIAL REPORT i l t 8 r n n n n 1 o e e r t g o o c s s t I l N . S B A R D O O G R R O C S N L L E E T E E T I N I L T N N N E M E

Notes to the Consolidated Financial Statements > 127 In December 2012, the Fund acquired Greenwich, Amherstburg and Tilbury solar energy projects, Hardisty Caverns and Hardisty Contract Terminals from Enbridge and wholly-owned subsidiaries of Enbridge for proceeds of $1.2 billion. In October 2011, the Fund acquired the Ontario Wind, Sarnia Solar and Talbot Wind energy projects from a wholly-owned subsidiary of Enbridge for $1.2 billion. In both cases, ordinary trust units were issued by the Fund to partially finance these acquisitions, resulting in an increase in interests held by third parties in 2012 and 2011 and contributions from noncontrolling unitholders of $226 million and $168 million, respectively. Distributions to noncontrolling unitholders are made on a monthly basis in line with the Fund’s objective of distributing a high proportion of its cash available for distribution, as approved by its Board of Trustees. 19. Share Capital The authorized share capital of the Company consists of an unlimited number of common shares with no par value and an unlimited number of preference shares. COMMON SHARES 2012 2011 2010 December 31, Number of Shares Amount Number of Shares Amount Number of Shares Amount (millions of Canadian dollars; number of common shares in millions) Balance at beginning of year 781 3,969 770 3,683 756 3,379 Common Shares issued 1 10 388 – – – – Shares issued on exercise of stock options 6 78 4 57 6 80 Dividend Reinvestment and Share Purchase Plan (DRIP) 8 297 7 229 8 224 Balance at end of year 805 4,732 781 3,969 770 3,683 1 Gross proceeds – $400 million; net issuance costs – $12 million. PREFERENCE SHARES 2012 2011 2010 December 31, Number of Shares Amount Number of Shares Amount Number of Shares Amount (millions of Canadian dollars; number of preference shares in millions) Preference Shares, Series A 5 125 5 125 5 125 Preference Shares, Series B 20 500 20 500 – – Preference Shares, Series D 18 450 18 450 – – Preference Shares, Series F 20 500 – – – – Preference Shares, Series H 14 350 – – – – Preference Shares, Series J 8 199 – – – – Preference Shares, Series L 16 411 – – – – Preference Shares, Series N 18 450 – – – – Preference Shares, Series P 16 400 – – – – Preference Shares, Series R 16 400 – – – – Issuance costs (78) (19) – Balance at end of year 3,707 1,056 125 C i 1 e h p r t 9 a S a al . O S S M O ARE C H N M F PR A E E R R H S C S N E E E

Characteristics of the preference shares are as follows: Initial Yield Dividend 1 Per Share Base Redemption Value 2 Redemption and Conversion Option Date 2,3 Right to Convert Into 3,4 (Canadian dollars unless otherwise stated) Preference Shares, Series A 5.5% $1.375 $25 – – Preference Shares, Series B 4.0% $1.000 $25 June 1, 2017 Series C Preference Shares, Series D 4.0% $1.000 $25 March 1, 2018 Series E Preference Shares, Series F 4.0% $1.000 $25 June 1, 2018 Series G Preference Shares, Series H 4.0% $1.000 $25 September 1, 2018 Series I Preference Shares, Series J 4.0% US$1.000 US$25 June 1, 2017 Series K Preference Shares, Series L 4.0% US$1.000 US$25 September 1, 2017 Series M Preference Shares, Series N 4.0% $1.000 $25 December 1, 2018 Series O Preference Shares, Series P 4.0% $1.000 $25 March 1, 2019 Series Q Preference Shares, Series R 5 4.0% $1.000 $25 June 1, 2019 Series S 1 The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend per year, as declared by the Board of Directors of the Company. 2 Preference Shares, Series A may be redeemed any time at the Company’s option. For all other series of Preference Shares, the Company may at its option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on the Conversion Option Date and every fifth anniversary thereafter. 4 Holders will be entitled to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/365) x (90-day Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q) or 2.5% (Series S)); or US$25 x (number of days in quarter/365) x (90-day United States Government treasury bill rate + 3.1% (Series K) or 3.2% (Series M)). 5 A cash dividend of $0.2356 per share will be paid on March 1, 2013 to Series R shareholders. The regular quarterly dividend of $0.25 per share will begin in the second quarter of 2013. EARNINGS PER COMMON SHARE Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding. The weighted average number of shares outstanding has been reduced by the Company’s pro-rata weighted average interest in its own common shares of 20 million (2011 – 25 million; 2010 – 22 million), resulting from the Company’s reciprocal investment in Noverco. The treasury stock method is used to determine the dilutive impact of stock options. This method assumes any proceeds from the exercise of stock options would be used to purchase common shares at the average market price during the period. December 31, 2012 2011 2010 (number of common shares in millions) Weighted average shares outstanding 772 751 741 Effect of dilutive options 13 10 7 Diluted weighted average shares outstanding 785 761 748 For the year ended December 31, 2012, 5,733,000 anti-dilutive stock options (2011 – 48,000; 2010 – 92,000) with a weighted average exercise price of $38.32 (2011 – $32.02; 2010 – $27.84) were excluded from the diluted earnings per share calculation. STOCK SPLIT Effective May 25, 2011, a two-for-one split of the common shares of the Company was completed. All references to the number of shares outstanding, earnings per common share, diluted earnings per common share, dividends per common share and outstanding option information have been retroactively restated to reflect the impact of the stock split. 128 < ENBRIDGE INC. 2012 FINANCIAL REPORT O O P R A AR R H E E G S C S N M M N I N E O P S S T K C LI T

Notes to the Consolidated Financial Statements > 129 DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN Under the DRIP, registered shareholders may reinvest dividends in common shares of the Company and make additional optional cash payments to purchase common shares, free of brokerage or other charges. Participants in the Company’s DRIP receive a 2% discount on the purchase of common shares with reinvested dividends. SHAREHOLDER RIGHTS PLAN The Shareholder Rights Plan is designed to encourage the fair treatment of shareholders in connection with any takeover offer for the Company. Rights issued under the plan become exercisable when a person and any related parties acquires or announces its intention to acquire 20% or more of the Company’s outstanding common shares without complying with certain provisions set out in the plan or without approval of the Company’s Board of Directors. Should such an acquisition occur, each rights holder, other than the acquiring person and related parties, will have the right to purchase common shares of the Company at a 50% discount to the market price at that time. 20. Stock Option and Stock Unit Plans The Company maintains four long-term incentive compensation plans: the ISO Plan, the PBSO Plan, the PSU Plan and the RSU Plan. A maximum of 60 million common shares were reserved for issuance under the 2002 ISO plan, of which 46 million have been issued to date. In 2007, a new reserve of 33 million shares was approved and established and in 2011 an increase of 19 million to the reserved common shares was approved, resulting in a total of 52 million common shares being available for the 2007 ISO and PBSO plans, of which four million have been issued to date. The PSU and RSU plans grant notional units as if a unit was one Enbridge common share and are payable in cash. INCENTIVE STOCK OPTIONS Key employees are granted ISOs to purchase common shares at the market price on the grant date. ISOs vest in equal annual installments over a four-year period and expire 10 years after the issue date. December 31, 2012 Number Weighted Average Exercise Price Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (options in thousands; intrinsic value in millions of Canadian dollars) Options outstanding at beginning of year 27,465 21.19 Options granted 5,802 38.32 Options exercised 1 (5,796) 16.99 Options cancelled or expired (103) 27.78 Options outstanding at end of year 27,368 25.69 6.7 375 Options vested at end of year 2 13,703 20.33 5.2 261 1 The total intrinsic value of ISOs exercised during the year ended December 31, 2012 was $130 million (2011 – $68 million; 2010 – $38 million) and cash received on exercise was $69 million (2011 – $56 million; 2010 – $50 million). 2 The total fair value of options vested under the ISO Plan during the year ended December 31, 2012 was $19 million (2011 – $17 million; 2010 – $14 million). C S S D I D P P R D D A N H R R E A A A S U NV E N L E H N T E M T E I E N I V G O P D S A R R R H E A S E N L T H I L H O S i P 0 t 2 i ns p o n c n t n a k d o o S a c U t l t k . O O S N N P O T E E S C C N I T K V I T I

Weighted average assumptions used to determine the fair value of the ISOs using the Black-Scholes-Merton option pricing model are as follows: Year ended December 31, 2012 2011 2010 Fair value per option (Canadian dollars) 1 4.81 4.19 3.44 Valuation assumptions Expected option term (years) 2 5 6 6 Expected volatility 3 19.7% 18.6% 19.7% Expected dividend yield 4 3.0% 3.4% 3.6% Risk-free interest rate 5 1.3% 2.9% 2.7% 1 Options granted to United States employees are based on New York Stock Exchange prices. The option value and assumptions shown are based on a weighted average of the United States and the Canadian options. The fair values per option were $4.65 (2011 – $4.01; 2010 – $3.28) for Canadian employees and US$5.58 (2011 – US$5.11; 2010 – US$4.00) for United States employees. 2 The expected option term is based on historical exercise practice. 3 Expected volatility is determined with reference to historic daily share price volatility and consideration of the implied volatility observable in call option values near the grant date. 4 The expected dividend yield is the current annual dividend at the grant date divided by the current stock price. 5 The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the United States Treasury Bond Yields. Compensation expense recorded for the year ended December 31, 2012 for ISOs was $23 million (2011 – $16 million; 2010 – $11 million). At December 31, 2012, unrecognized compensation cost related to non-vested stock-based compensation arrangements granted under the ISO Plan was $30 million. The cost is expected to be fully recognized over a weighted average period of approximately three years. PERFORMANCE BASED STOCK OPTIONS PBSOs are granted to executive officers and become exercisable when both performance targets and time vesting requirements have been met. PBSOs were granted on September 16, 2002 under the 2002 plan and on August 15, 2007, February 19, 2008 and August 15, 2012 under the 2007 plan. All performance and time vesting conditions on the 2002 grant were met prior to the term of the options expiring on September 16, 2010. All performance targets for the 2007 and 2008 grants have been met. The time vesting requirements were fulfilled evenly over a five-year period ending on August 15, 2012 with the options being exercisable until August 15, 2015. Time vesting requirements for the 2012 grant will be fulfilled evenly over a five-year term, ending August 15, 2017. The 2012 grant’s performance targets are based on the Company’s share price and must be met by February 15, 2019 or the options expire. If targets are met by February 15, 2019, the options are exercisable until August 15, 2020. December 31, 2012 Number Weighted Average Exercise Price Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (options in thousands; intrinsic value in millions of Canadian dollars) Options outstanding at beginning of year 4,127 18.52 Options granted 3,543 39.34 Options exercised 1 (966) 18.29 Options outstanding at end of year 6,704 29.56 5.3 66 Options vested at end of year 2 3,061 18.54 2.6 64 1 The total intrinsic value of PBSOs exercised during the year ended December 31, 2012 was $20 million (2011 – $2 million; 2010 – $26 million) and cash received on exercise was $12 million (2011 – $3 million; 2010 – $27 million). 2 The total fair value of options vested under the PBSO Plan during the year ended December 31, 2012 was $1 million (2011 – $2 million; 2010 – $2 million). 130 < ENBRIDGE INC. 2012 FINANCIAL REPORT O O S C B P P D R R O OC S A K E F A S E E N I T T N M

Notes to the Consolidated Financial Statements > 131 Assumptions used to determine the fair value of the PBSOs using the Bloomberg barrier option valuation model are as follows: Year ended December 31, 2012 Fair value per option (Canadian dollars) 4.25 Valuation assumptions Expected option term (years) 1 8 Expected volatility 2 16.1% Expected dividend yield 3 2.8% Risk-free interest rate 4 1.6% 1 The expected option term is based on historical exercise practice. 2 Expected volatility is determined with reference to historic daily share price volatility. 3 The expected dividend yield is the current annual dividend at the grant date divided by the current stock price. 4 The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields. Compensation expense recorded for the year ended December 31, 2012 for PBSOs was $2 million (2011 – $2 million; 2010 – $2 million). At December 31, 2012, unrecognized compensation cost related to non-vested stock-based compensation arrangements granted under the PBSO Plan was $14 million. The cost is expected to be fully recognized over a weighted average period of approximately two years. PERFORMANCE STOCK UNITS The Company has a PSU Plan for executives where cash awards are paid following a three-year performance cycle. Awards are calculated by multiplying the number of units outstanding at the end of the performance period by the Company’s weighted average share price for 20 days prior to the maturity of the grant and by a performance multiplier. The performance multiplier ranges from zero, if the Company’s performance fails to meet threshold performance levels, to a maximum of two if the Company performs within the highest range of its performance targets. The 2010, 2011 and 2012 grants derive the performance multiplier through a calculation of the Company’s price/earnings ratio relative to a specified peer group of companies and the Company’s earnings per share, adjusted for unusual, non-operating or non-recurring items, relative to targets established at the time of grant. To calculate the 2012 expense, multipliers of two, based upon multiplier estimates at December 31, 2012, were used for each of the 2010, 2011 and 2012 PSU grants. December 31, 2012 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 937 Units granted 307 Units matured 1 (627) Dividend reinvestment 35 Units outstanding at end of year 652 1.5 56 1 The total amount paid during the year ended December 31, 2012 for PSUs was $25 million (2011 – $17 million; 2010 – $14 million). Compensation expense recorded for the year ended December 31, 2012 for PSUs was $49 million (2011 – $42 million; 2010 – $27 million). As at December 31, 2012, unrecognized compensation expense related to non-vested units granted under the PSU Plan was $25 million and is expected to be fully recognized over a weighted average period of approximately two years. O P O S C A R R E F C S U M E T I N K T N

RESTRICTED STOCK UNITS Enbridge has a RSU Plan where cash awards are paid to certain non-executive employees of the Company following a 35 month maturity period. RSU holders receive cash equal to the Company’s weighted average share price for 20 days prior to the maturity of the grant multiplied by the units outstanding on the maturity date. December 31, 2012 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 1,902 Units granted 891 Units cancelled (114) Units matured 1 (939) Dividend reinvestment 79 Units outstanding at end of year 1,819 1.5 78 1 The total amount paid during the year ended December 31, 2012 for RSUs was $37 million (2011 – $39 million; 2010 – $24 million). Compensation expense recorded for the year ended December 31, 2012 for RSUs was $32 million (2011 – $31 million; 2010 – $29 million). As at December 31, 2012, unrecognized compensation expense related to non-vested units granted under the RSU Plan was $37 million and is expected to be fully recognized over a weighted average period of approximately two years. 21. Components of Accumulated Other Comprehensive Loss Changes in AOCI attributable to Enbridge common shareholders for the years ended December 31, 2012, 2011 and 2010, are as follows: Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Actuarial Gain/(Loss) Adjustment Total (millions of Canadian dollars) Balance at January 1, 2010 69 429 (1,033) (15) (104) (654) Changes during the year (136) 61 (255) 3 (52) (379) Tax impact 1 (10) – 1 14 6 (135) 51 (255) 4 (38) (373) Balance at December 31, 2010 (66) 480 (1,288) (11) (142) (1,027) Changes during the year (563) (21) 85 (20) (200) (719) Tax impact 153 2 – 3 56 214 (410) (19) 85 (17) (144) (505) Balance at December 31, 2011 (476) 461 (1,203) (28) (286) (1,532) Changes during the year (190) 16 (99) 7 (52) (318) Tax impact 45 (3) – (5) 14 51 (145) 13 (99) 2 (38) (267) Balance at December 31, 2012 (621) 474 (1,302) (26) (324) (1,799) 132 < ENBRIDGE INC. 2012 FINANCIAL REPORT C O S D TR E R E K S C S U T I N T T I C C 1 f 2 i s n n h m mp e e e o c o m d o e e e s n h r t pr O a A o o cu s s . t u v L l t

Notes to the Consolidated Financial Statements > 133 22. Derivative Financial Instruments and Hedging Activities MARKET PRICE RISK The Company’s earnings, cash flows and OCI are subject to movements in foreign exchange rates, interest rates, commodity prices and the Company’s share price (collectively, market price risk). Formal risk management policies, processes and systems have been designed to mitigate these risks. The following summarizes the types of market price risks to which the Company is exposed and the risk management instruments used to mitigate them. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below. FOREIGN EXCHANGE RISK The Company’s earnings, cash flows, and OCI are subject to foreign exchange rate variability, primarily arising from its United States dollar denominated investments and subsidiaries, and certain revenues denominated in United States dollars and certain expenses denominated in Euros. The Company has implemented a policy where it economically hedges a minimum level of foreign currency denominated earnings exposures identified over the next five year period. The Company may also hedge anticipated foreign currency denominated purchases or sales, foreign currency denominated debt, as well as certain equity investment balances and net investments in foreign denominated subsidiaries. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage variability in cash flows arising from its United States dollar investments and subsidiaries, and primarily non-qualifying derivative instruments to manage variability arising from certain revenues denominated in United States dollars. INTEREST RATE RISK The Company’s earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of its variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps and options are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense through 2016 with an average swap rate of 2.2%. The Company’s earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate its exposure to long-term interest rate variability on select forecast term debt issuances through 2016. A total of $10,547 million of future fixed rate term debt issuances have been hedged at an average swap rate of 3.5%. The Company also monitors its debt portfolio mix of fixed and variable rate debt instruments to maintain a consolidated portfolio of debt which stays within its Board of Directors approved policy limit band of a maximum of 25% floating rate debt as a percentage of total debt outstanding. The Company uses primarily qualifying derivative instruments to manage interest rate risk. COMMODITY PRICE RISK The Company’s earnings and cash flows are exposed to changes in commodity prices as a result of ownership interests in certain assets and investments, as well as through the activities of its energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. The Company employs financial derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. The Company uses primarily non-qualifying derivative instruments to manage commodity price risk. H I l i D 22 i i i i i i i n n me a r r d d e c g e e e s n n n t n a F a A g a s s c u t t v v t t v . P E R R R K A S C K I E I T M O R R A HA GN EXC FO G S XC REI SK RIS GE AN CHA EX G EI EST NT RA R ER R SK A RAT S RIS TE ATE T RES TER TE I O O C P D S R PR R SK CE C RIS RIC Y TY IT M M

EQUITY PRICE RISK Equity price risk is the risk of earnings fluctuations due to changes in the Company’s share price. The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, RSUs (Note 20). The Company uses a combination of qualifying and non-qualifying derivative instruments to manage equity price risk. TOTAL DERIVATIVE INSTRUMENTS The following table summarizes the balance sheet location and carrying value of the Company’s derivative instruments. The Company did not have any outstanding fair value hedges at December 31, 2012 or 2011. December 31, 2012 Derivative Instruments used as Cash Flow Hedges Derivative Instruments used as Net Investment Hedges Non-Qualifying Derivative Instruments Total Gross Derivative Instruments Effects of Netting Total Net Derivative Instruments 1 (millions of Canadian dollars) Accounts receivable and other (Note 7) Foreign exchange contracts 4 16 210 230 – 230 Interest rate contracts 7 – 11 18 (2) 16 Commodity contracts 18 – 127 145 (17) 128 Other contracts 3 – 6 9 – 9 32 16 354 402 (19) 383 Deferred amounts and other assets (Note 12) Foreign exchange contracts 11 79 225 315 – 315 Interest rate contracts 21 – 12 33 (3) 30 Commodity contracts 5 – 60 65 (5) 60 Other contracts 2 – 1 3 – 3 39 79 298 416 (8) 408 Accounts payable and other (Note 15) Foreign exchange contracts (5) – (100) (105) – (105) Interest rate contracts (673) – (2) (675) 2 (673) Commodity contracts (10) – (304) (314) 17 (297) (688) – (406) (1,094) 19 (1,075) Other long-term liabilities (Note 17) Foreign exchange contracts (41) (5) (23) (69) – (69) Interest rate contracts (293) – (15) (308) 3 (305) Commodity contracts (6) – (388) (394) 5 (389) (340) (5) (426) (771) 8 (763) Total net derivative asset/(liability) Foreign exchange contracts (31) 90 312 371 – 371 Interest rate contracts (938) – 6 (932) – (932) Commodity contracts 7 – (505) (498) – (498) Other contracts 5 – 7 12 – 12 (957) 90 (180) (1,047) – (1,047) 134 < ENBRIDGE INC. 2012 FINANCIAL REPORT PR R K S C U Q E I E I Y T I O S S D AT R R A TA UM E L T N E T N I E V I V I T

Notes to the Consolidated Financial Statements > 135 December 31, 2011 Derivative Instruments used as Cash Flow Hedges Derivative Instruments used as Net Investment Hedges Non-Qualifying Derivative Instruments Total Gross Derivative Instruments Effects of Netting Total Net Derivative Instruments 1 (millions of Canadian dollars) Accounts receivable and other (Note 7) Foreign exchange contracts 4 15 315 334 – 334 Interest rate contracts – – 12 12 (4) 8 Commodity contracts 7 – 146 153 (19) 134 Other contracts 3 – 7 10 – 10 14 15 480 509 (23) 486 Deferred amounts and other assets (Note 12) Foreign exchange contracts 15 79 203 297 – 297 Interest rate contracts 1 – 24 25 (3) 22 Commodity contracts 12 – 241 253 (15) 238 Other contracts 3 – 2 5 – 5 31 79 470 580 (18) 562 Accounts payable and other (Note 15) Foreign exchange contracts (4) – (275) (279) – (279) Interest rate contracts (477) – (8) (485) 4 (481) Commodity contracts (32) – (107) (139) 19 (120) (513) – (390) (903) 23 (880) Other long-term liabilities (Note 17) Foreign exchange contracts (35) (5) (51) (91) – (91) Interest rate contracts (415) – (20) (435) 3 (432) Commodity contracts (29) – (20) (49) 15 (34) (479) (5) (91) (575) 18 (557) Total net derivative asset/(liability) Foreign exchange contracts (20) 89 192 261 – 261 Interest rate contracts (891) – 8 (883) – (883) Commodity contracts (42) – 260 218 – 218 Other contracts 6 – 9 15 – 15 (947) 89 469 (389) – (389) 1 As presented in the Consolidated Statements of Financial Position.

The following table summarizes the maturity and notional principal or quantity outstanding related to the Company’s derivative instruments. December 31, 2012 2013 2014 2015 2016 2017 Thereafter Foreign exchange contracts – United States dollar forwards – purchase (millions of United States dollars) 558 468 25 25 413 6 Foreign exchange contracts – United States dollar forwards – sell (millions of United States dollars) 2,088 2,402 2,751 2,323 2,557 158 Foreign exchange contracts – Euro dollar forwards – purchase (millions of Euros) 6 – – – – – Interest rate contracts – short-term borrowings (millions of Canadian dollars) 3,644 3,591 3,455 3,157 2,841 171 Interest rate contracts – long-term debt (millions of Canadian dollars) 4,590 3,055 1,760 1,142 – – Equity contracts (millions of Canadian dollars) 39 36 – – – – Commodity contracts – natural gas (billions of cubic feet) 55 19 10 10 11 3 Commodity contracts – crude oil (millions of barrels) 37 38 29 23 18 9 Commodity contracts – NGL (millions of barrels) 1 2 – – – – Commodity contracts – power (megawatt hours (MWH)) 51 67 48 63 83 66 December 31, 2011 2012 2013 2014 2015 2016 Thereafter Foreign exchange contracts – United States dollar forwards – purchase (millions of United States dollars) 58 287 468 25 25 418 Foreign exchange contracts – United States dollar forwards – sell (millions of United States dollars) 2,017 1,865 2,182 2,583 2,039 180 Interest rate contracts – short-term borrowings (millions of Canadian dollars) 3,227 3,237 2,787 2,641 2,428 215 Interest rate contracts – long-term debt (millions of Canadian dollars) 2,650 2,000 1,650 750 – – Equity contracts (millions of Canadian dollars) 36 26 – – – – Commodity contracts – natural gas (billions of cubic feet) 20 59 1 1 1 – Commodity contracts – crude oil (millions of barrels) 11 26 17 8 7 10 Commodity contracts – NGL (millions of barrels) 4 1 – – – – Commodity contracts – power (MWH) 40 28 40 48 63 58 136 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Notes to the Consolidated Financial Statements > 137 THE EFFECT OF DERIVATIVE INSTRUMENTS ON THE STATEMENTS OF EARNINGS AND COMPREHENSIVE INCOME The following table presents the effect of cash flow hedges and net investment hedges on the Company’s consolidated earnings and consolidated comprehensive income, before the effect of income taxes. Year ended December 31, 2012 2011 2010 (millions of Canadian dollars) Amount of unrealized gains/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts (12) (22) (25) Interest rate contracts (46) (724) (217) Commodity contracts 52 72 128 Other contracts (3) 6 (1) Net investment hedges Foreign exchange contracts 1 (26) 19 (8) (694) (96) Amount of (gains)/loss reclassified from AOCI to earnings (effective portion) Foreign exchange contracts 1 1 1 (7) Interest rate contracts 2 (1) (10) 61 Commodity contracts 3 (3) (55) (116) Other contracts 4 2 (2) 1 (1) (66) (61) Amount of (gains)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing) Interest rate contracts 2 23 11 – Commodity contracts 3 (3) 5 (3) 20 16 (3) 1 Reported within Other income in the Consolidated Statements of Earnings. 2 Reported within Interest expense in the Consolidated Statements of Earnings. 3 Reported within Commodity costs in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. The Company estimates that $101 million of AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which the Company is hedging exposures to the variability of cash flows is 60 months at December 31, 2012. NON-QUALIFYING DERIVATIVES The following table presents the unrealized gains and losses associated with changes in the fair value of the Company’s non-qualifying derivatives. Year ended December 31, 2012 2011 2010 (millions of Canadian dollars) Foreign exchange contracts 1 120 (179) 33 Interest rate contracts 2 (2) 9 (3) Commodity contracts 3 (765) 280 (12) Other contracts 4 (2) 4 – Total unrealized derivative fair value gains/(loss) (649) 114 18 1 Reported within Transportation and other services revenues and Other income in the Consolidated Statements of Earnings. 2 Reported within Interest expense in the Consolidated Statements of Earnings. 3 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. S O O O O S S T S T O C F E P D D R R T R ER E M M M E M A E A VA V R EA F EN E FF F E F EF E A A T C S C U S N VE V G T VE V E N I E I N EN E H EH E N N I N TS N EN E TE TA E H TH T N TS TR N I TI T I T FE TH T Q O D R ER ATI ES VES FY - A VAT A UA VE AL VATIV RIV G NG YI LI ON NO

LIQUIDITY RISK Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including commitments and guarantees (Notes 28 and 29), as they become due. In order to manage this risk, the Company forecasts cash requirements over a 12 month rolling time period to determine whether sufficient funds will be available. The Company’s primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt which includes debentures and medium-term notes. The Company maintains current shelf prospectuses with securities regulators, which enables, subject to market conditions, ready access to either the Canadian or United States public capital markets. In addition, the Company maintains sufficient liquidity through committed credit facilities (Note 16) with a diversified group of banks and institutions which, if necessary, enables the Company to fund all anticipated requirements for one year without accessing the capital markets. The Company is in compliance with all the terms and conditions of its committed credit facilities as at December 31, 2012. As a result, all credit facilities are available to the Company and the banks are obligated to fund and have been funding the Company under the terms of the facilities. CREDIT RISK Entering into derivative financial instruments may result in exposure to credit risk. Credit risk arises from the possibility that a counterparty will default on its contractual obligations. The Company enters into risk management transactions primarily with institutions that possess investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated by credit exposure limits and contractual requirements, frequent assessment of counterparty credit ratings and netting arrangements. The Company generally has a policy of entering into individual International Swaps and Derivatives Association (ISDA) agreements, or other similar derivative agreements, with the majority of its derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit event, and would reduce the Company’s credit risk exposure on derivative asset positions outstanding with these counterparties in these particular circumstances. At December 31, 2012 and 2011, the Company had group credit concentrations and maximum credit exposure, with respect to derivative instruments, in the following counterparty segments: December 31, 2012 2011 (millions of Canadian dollars) Canadian financial institutions 306 431 United States financial institutions 129 287 European financial institutions 244 257 Other 1 128 112 807 1,087 1 Other is comprised of commodity clearing house and natural gas and crude physical counterparties. As at December 31, 2012, the Company had provided letters of credit totaling $273 million in lieu of providing cash collateral to its counterparties pursuant to the terms of the relevant ISDA agreements. The Company holds no cash collateral on asset exposures at December 31, 2012 or 2011. Gross derivative balances have been presented without the effects of collateral posted. Derivative assets are adjusted for non-performance risk of the Company’s counterparties using their credit default swap spread rates and are reflected in the fair value. For derivative liabilities, the Company’s non-performance risk is considered in the valuation. 138 < ENBRIDGE INC. 2012 FINANCIAL REPORT Q D T R Y U SK I I I I L D R S R K C E I T I

Notes to the Consolidated Financial Statements > 139 Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Credit risk is mitigated by the large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. The Company actively monitors the financial strength of large industrial customers and, in select cases, has obtained additional security to minimize the risk of default on receivables. Generally, the Company classifies and provides for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value. FAIR VALUE MEASUREMENTS The Company’s financial assets and liabilities measured at fair value on a recurring basis include derivative instruments. The Company also discloses the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects the Company’s best estimates of market value based on generally accepted valuation techniques or models and supported by observable market prices and rates. When such values are not available, the Company uses discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value. FAIR VALUE OF DERIVATIVES The Company categorizes its derivative instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. LEVEL 1 Level 1 includes derivatives measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a derivative is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. The Company’s Level 1 instruments consist primarily of exchange-traded derivatives used to mitigate the risk of crude oil price fluctuations. The Company does not have any other financial instruments categorized as Level 1. LEVEL 2 Level 2 includes derivative valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Derivatives in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the derivative. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange forward and cross currency swap contracts, interest rate swaps, physical forward commodity contracts, as well as commodity swaps and options for which observable inputs can be obtained. The Company has also categorized the fair value of its held to maturity preferred share investment and long-term debt as Level 2. The fair value of the Company’s held to maturity preferred share investment is primarily based on the yield of certain Government of Canada bonds. The fair value of the Company’s long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor. LEVEL 3 Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the derivatives’ fair value. Generally, Level 3 derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. The Company has developed methodologies, benchmarked against industry standards, to determine fair value for these derivatives based on extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power contracts and NGL and natural gas contracts. The Company does not have any other financial instruments categorized in Level 3. F S A R M R A A U S U E T N E M E E L V I O ES D A FA R ER R A VAT A VALU VA VE VA VES TIV ATI RIV E AL AI VEL LEV L EL LEVE VEL L VEL VE L

The Company uses the most observable inputs available to estimate the fair value of its derivatives. When possible, the Company estimates the fair value of its derivatives based on quoted market prices. If quoted market prices are not available, the Company uses estimates from third party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, the Company uses standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, the Company uses observable market prices (interest, foreign exchange, commodity and share) and volatility as primary inputs to these valuation techniques. Finally, the Company considers its own credit default swap spread as well as the credit default swap spreads associated with its counterparties in its estimation of fair value. The Company has categorized its derivative assets and liabilities measured at fair value as follows: December 31, 2012 Level 1 Level 2 Level 3 Total Gross Derivative Instruments Effects of Netting Total (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts – 230 – 230 – 230 Interest rate contracts – 18 – 18 (2) 16 Commodity contracts 3 24 118 145 (17) 128 Other contracts – 9 – 9 – 9 3 281 118 402 (19) 383 Long-term derivative assets Foreign exchange contracts – 315 – 315 – 315 Interest rate contracts – 33 – 33 (3) 30 Commodity contracts – 56 9 65 (5) 60 Other contracts – 3 – 3 – 3 – 407 9 416 (8) 408 Financial liabilities Current derivative liabilities Foreign exchange contracts – (105) – (105) – (105) Interest rate contracts – (675) – (675) 2 (673) Commodity contracts (9) (229) (76) (314) 17 (297) (9) (1,009) (76) (1,094) 19 (1,075) Long-term derivative liabilities Foreign exchange contracts – (69) – (69) – (69) Interest rate contracts – (308) – (308) 3 (305) Commodity contracts – (319) (75) (394) 5 (389) – (696) (75) (771) 8 (763) Total net financial asset/(liability) Foreign exchange contracts – 371 – 371 – 371 Interest rate contracts – (932) – (932) – (932) Commodity contracts (6) (468) (24) (498) – (498) Other contracts – 12 – 12 – 12 (6) (1,017) (24) (1,047) – (1,047) 140 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Notes to the Consolidated Financial Statements > 141 December 31, 2011 Level 1 Level 2 Level 3 Total Gross Derivative Instruments Effects of Netting Total (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts – 334 – 334 – 334 Interest rate contracts – 12 – 12 (4) 8 Commodity contracts 1 66 86 153 (19) 134 Other contracts – 10 – 10 – 10 1 422 86 509 (23) 486 Long-term derivative assets Foreign exchange contracts – 297 – 297 – 297 Interest rate contracts – 25 – 25 (3) 22 Commodity contracts – 208 45 253 (15) 238 Other contracts – 5 – 5 – 5 – 535 45 580 (18) 562 Financial liabilities Current derivative liabilities Foreign exchange contracts – (279) – (279) – (279) Interest rate contracts – (485) – (485) 4 (481) Commodity contracts – (59) (80) (139) 19 (120) – (823) (80) (903) 23 (880) Long-term derivative liabilities Foreign exchange contracts – (91) – (91) – (91) Interest rate contracts – (435) – (435) 3 (432) Commodity contracts – (30) (19) (49) 15 (34) – (556) (19) (575) 18 (557) Total net financial asset/(liability) Foreign exchange contracts – 261 – 261 – 261 Interest rate contracts – (883) – (883) – (883) Commodity contracts 1 185 32 218 – 218 Other contracts – 15 – 15 – 15 1 (422) 32 (389) – (389)

The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows: December 31, 2012 Fair Value Unobservable Input Minimum Price Maximum Price Weighted Average Price (Fair value in millions of Canadian dollars) Commodity contracts – financial 1 Natural gas 8 Forward gas price 3.21 4.31 3.54 $/mmbtu3 Crude (3) Forward crude price 58.42 108.14 100.40 $/barrel Power (60) Forward power price 50.25 68.25 55.98 $/MWH Commodity contracts – physical 1 Natural gas (12) Forward gas price 2.88 5.10 3.67 $/mmbtu3 Crude 37 Forward crude price 51.13 116.56 92.49 $/barrel NGL 1 Forward NGL price 0.00 2.54 1.42 $/gallon Power (1) Forward power price 30.09 36.35 32.74 $/MWH Commodity options 2 Natural gas 1 Option volatility 29.0% 36.0% 34.0% NGL 5 Option volatility 33.0% 104.0% 57.0% (24) 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 Commodity options contracts are valued using an option model valuation technique. 3 One million British thermal units (mmbtu). If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair value of the Company’s Level 3 derivative instruments. The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity prices and, for option contracts, price volatility. Changes in forward commodity prices would result in significantly different fair values for the Company’s Level 3 derivatives. Changes in price volatility would change the value of the option contracts. Generally speaking, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of price volatility. Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows: Year ended December 31, 2012 2011 (millions of Canadian dollars) Level 3 net derivative asset/(liability) at beginning of year 32 (24) Total unrealized gains/(loss) Included in earnings 1 (69) 31 Included in OCI 13 (41) Purchases – 8 Settlements – 58 Level 3 net derivative asset/(liability) at end of year (24) 32 1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. The Company’s policy is to recognize transfers as of the last day of the reporting period. There were no transfers between levels as at December 31, 2012 or 2011. 142 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Notes to the Consolidated Financial Statements > 143 FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS The Company recognizes equity investments in other entities not categorized as held to maturity at fair value, with changes in fair value recorded in OCI, unless actively quoted prices are not available for fair value measurement in which case these investments are recorded at cost. The carrying value of all equity investments recognized at cost totaled $66 million at December 31, 2012 (2011 – $57 million). The Company has a held to maturity preferred share investment carried at its amortized cost of $246 million at December 31, 2012 (2011 – $285 million). These preferred shares are entitled to a cumulative preferred dividend based on the average yield of Government of Canada bonds maturing in greater than 10 years plus a range of 4.3% to 4.4%. At December 31, 2012, the fair value of this preferred share investment approximates its face value of $580 million (2011 – $580 million). At December 31, 2012, the Company’s long-term debt had a carrying value of $20,855 million (2011 – $19,605 million) and a fair value of $24,809 million (2011 – $22,620 million). 23. Income Taxes INCOME TAX RATE RECONCILIATION Year ended December 31, 2012 2011 2010 (millions of Canadian dollars) Earnings before income taxes and extraordinary loss 1,071 2,030 1,008 Combined statutory income tax rate 25.8% 27.2% 28.8% Income taxes at statutory rate 276 552 290 Increase/(decrease) resulting from: Deferred income taxes related to regulated operations (67) (35) (62) Higher/(lower) foreign tax rates (56) 65 (38) Tax rates and legislated tax changes 9 1 (15) Non-taxable items, net (6) (16) (8) Intercompany sale of investments 1 56 98 – Noncontrolling interests in Limited Partnerships (79) (130) 55 Other (5) (9) 5 Income taxes before extraordinary loss 128 526 227 Effective income tax rate 12.0% 25.9% 22.5% 1 In December 2012 and October 2011, Enbridge and certain wholly-owned subsidiaries of Enbridge sold certain assets to the Fund. As these transactions occurred between entities under common control of the Company, the intercompany gains realized as a result of these transfers have been eliminated, although current income tax expense of $56 million and $98 million remain as a charge to earnings in 2012 and 2011, respectively. The Company retains the benefit of cash taxes paid in the form of increased tax basis of its investment in the underlying entities; however, accounting recognition of such benefit is not permitted until such time as the entities are sold outside of the consolidated group. O O S T S VA V FA F R ER E R A IA I R T EN E FI F F A NA N A A C U U L TS N M TR N I L N TH T E I 3 n a Ta m o e es c . 2 x I O C O C A TA AT R R X E O A A C L E E N I AT I I N M N I

COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES Year ended December 31, 2012 2011 2010 (millions of Canadian dollars) Earnings before income taxes and extraordinary loss Canada 1,041 694 759 United States (177) 1,203 118 Other 207 133 131 1,071 2,030 1,008 Current income taxes Canada 130 194 (24) United States 35 (30) 43 Other 3 (6) 5 168 158 24 Deferred income taxes Canada 160 30 136 United States (200) 338 67 (40) 368 203 Total income taxes before extraordinary loss 128 526 227 COMPONENTS OF DEFERRED INCOME TAXES Deferred tax assets and liabilities are recognized for the future tax consequences of differences between carrying amounts of assets and liabilities and their respective tax bases. Major components of deferred income tax assets and liabilities are: December 31, 2012 2011 (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment (1,325) (1,499) Investments (1,479) (973) Regulatory liabilities (221) (197) Other (144) (117) Total deferred income tax liabilities (3,169) (2,786) Deferred income tax assets Financial instruments 380 37 Pension and OPEB plans 180 145 Loss carryforwards 161 174 Other 51 29 Total deferred income tax assets 772 385 Less valuation allowance (27) (45) Total deferred income tax assets, net 745 340 Net deferred income tax liabilities (2,424) (2,446) Presented as follows: Assets Accounts receivable and other (Note 7) 167 135 Deferred income taxes 10 41 Total deferred income tax assets 177 176 Liabilities Accounts payable and other (Note 15) – (7) Deferred income taxes (2,601) (2,615) Total deferred income tax liabilities (2,601) (2,622) Net deferred income tax liabilities (2,424) (2,446) 144 < ENBRIDGE INC. 2012 FINANCIAL REPORT C O O O P P R D S S A TA A R X X E E F O A A TA C S N E E E M N I N G N I N T N M S O C O P D D O T R R X E F F O A TA C S M E E N I E E N E N M

Notes to the Consolidated Financial Statements > 145 Valuation allowances have been established for certain loss and credit carryforwards that reduce deferred income tax assets to an amount that will more likely than not be realized. At December 31, 2012, the Company recognized the benefit of unused tax loss carryforwards of $183 million (2011 – $214 million) in Canada which start to expire in 2022 and beyond. At December 31, 2012, the Company recognized the benefit of unused tax loss carryforwards of $222 million (2011 – $187 million) in the United States which start to expire in 2022 and beyond. The Company has not provided for deferred income taxes on $548 million (2011 – $524 million) of foreign subsidiaries’ undistributed earnings as at December 31, 2012 as such earnings are intended to be indefinitely reinvested in the operations and potential acquisitions. Upon distribution of these earnings in the form of dividends or otherwise, the Company would be subject to income taxes. It is not practicable to determine the income tax liability that might be incurred if these earnings were to be distributed. The Company recognizes accrued interest and penalties related to unrecognized tax benefits as a component of Income taxes. Income tax expense for the year ended December 31, 2012 included $1 million (2011 – $1 million; 2010 – $2 million recovery) of interest and penalties. As at December 31, 2012, interest and penalties of $10 million (2011 – $9 million) have been accrued. The Company and one or more of its subsidiaries are subject to taxation in Canada, the United States and other foreign jurisdictions. The Company is under examination by certain tax authorities for the 2007 to 2011 tax years. The material jurisdictions in which the Company is subject to potential examinations include the United States (Federal and Texas) and Canada (Federal, Alberta and Ontario). UNRECOGNIZED TAX BENEFITS Year ended December 31, 2012 2011 (millions of Canadian dollars) Unrecognized tax benefits at beginning of year 18 17 Gross increases for tax positions of current year 38 3 Gross decreases for tax positions of prior years 3 (1) Reduction for lapse of statute of limitations (5) (1) Unrecognized tax benefits at end of year 54 18 The unrecognized tax benefits at December 31, 2012, if recognized, would affect the Company’s effective income tax rate. The gross increases for current year positions included $16 million in respect of filing positions based on substantively enacted tax law and $22 million in respect of a request for refund of Texas Gross Margin Tax. Although U.S. GAAP only permits recognition of tax positions based on enacted law it is widely accepted by the Canadian tax authorities to file and remit taxes based on substantively enacted tax law. It is anticipated that the law will be enacted in 2013. B D C RE X F OG A TA U S T I E N E E Z I N N

24. Retirement and Postretirement Benefits PENSION PLANS The Company has three registered pension plans which provide either defined benefit or defined contribution pension benefits, or both, to employees of the Company. The Liquids Pipelines and Gas Distribution pension plans (collectively, the Canadian Plans) provide Company funded defined benefit pension and/or defined contribution benefits to Canadian employees of Enbridge. The Enbridge United States pension plan (the United States Plan) provides Company funded defined benefit pension benefits for United States based employees. The Company has four supplemental pension plans which provide pension benefits in excess of the basic plans for certain employees. A measurement date of December 31, 2012 was used to determine the plan assets and accrued benefit obligation for the Canadian and United States plans. DEFINED BENEFIT PLANS Benefits payable from the defined benefit plans are based on members’ years of service and final average remuneration. These benefits are partially inflation indexed after a member’s retirement. Contributions by the Company are made in accordance with independent actuarial valuations and are invested primarily in publicly-traded equity and fixed income securities. The effective dates of the most recent actuarial valuations and the next required actuarial valuations for the basic plans are as follows: Effective Date of Most Recently Filed Actuarial Valuation Effective Date of Next Required Actuarial Valuation Canadian Plans Liquids Pipelines December 31, 2011 December 31, 2012 Gas Distribution December 31, 2009 December 31, 2012 United States Plan December 31, 2011 December 31, 2012 DEFINED CONTRIBUTION PLANS Contributions are generally based on the employee’s age, years of service and remuneration. For defined contribution plans, benefit costs equal amounts required to be contributed by the Company. OTHER POSTRETIREMENT BENEFITS OPEB primarily includes supplemental health and dental, health spending account and life insurance coverage for qualifying retired employees. 146 < ENBRIDGE INC. 2012 FINANCIAL REPORT f B i P R 2 i ir n n n m a me o e i r e e e e e e s n t t tr d 4 s . t t t O S P P A N S N E L I N D P B D ED EFI EFI A LA S EF ANS PL T FIT EF EN BEN N FI O O S EF D P B D ED R TR A LA EFI C UT ON ONT TIO TI RI N FI O S P B OS T T T T T E R R R H FI E N E N E M E I E

Notes to the Consolidated Financial Statements > 147 BENEFIT OBLIGATIONS AND FUNDED STATUS The following tables detail the changes in the benefit obligation, the fair value of plan assets and the recorded asset or liability for the Company’s defined benefit pension plans and OPEB plans using the accrual method. Pension OPEB December 31, 2012 2011 2012 2011 (millions of Canadian dollars) Change in accrued benefit obligation Benefit obligation at beginning of year 1,686 1,323 243 195 Service cost 84 61 8 6 Interest cost 74 73 10 11 Employees’ contributions – – 1 1 Actuarial loss 106 270 14 28 Benefits paid (64) (54) (8) (7) Effect of foreign exchange rate changes (5) 5 (2) 2 Other (2) 8 (5) 7 Benefit obligation at end of year 1,879 1,686 261 243 Change in plan assets Fair value of plan assets at beginning of year 1,355 1,314 54 41 Actual return on plan assets 117 16 5 1 Employer’s contributions 97 72 13 13 Employees’ contributions – – 1 1 Benefits paid (64) (54) (8) (7) Effect of foreign exchange rate changes (3) 3 (1) 1 Other (2) 4 (2) 4 Fair value of plan assets at end of year 1,500 1,355 62 54 Underfunded status at end of year (379) (331) (199) (189) Presented as follows: Accounts payable and other – – (5) (5) Other long-term liabilities (Note 17) (379) (331) (194) (184) (379) (331) (199) (189) The weighted average assumptions made in the measurement of the projected benefit obligations of the pension plans and OPEB are as follows: Pension OPEB Year ended December 31, 2012 2011 2010 2012 2011 2010 Discount rate 4.2% 4.5% 5.6% 4.0% 4.4% 5.6% Average rate of salary increases 3.7% 3.5% 3.5% O S E B B D D D O S A TAT A TA AT T F F U S U E AT E N N N I G I L I N

NET BENEFIT COSTS RECOGNIZED Pension OPEB Year ended December 31, 2012 2011 2010 2012 2011 2010 (millions of Canadian dollars) Benefits earned during the year 84 61 48 8 6 5 Interest cost on projected benefit obligations 74 73 72 10 11 11 Expected return on plan assets (93) (92) (80) (3) (3) (2) Amortization of prior service costs 2 2 2 – 1 – Amortization of actuarial loss 51 25 19 2 1 1 Net defined benefit costs on an accrual basis 118 69 61 17 16 15 Defined contribution benefit costs 4 4 5 – – – Net benefit cost recognized in the Consolidated Statements of Earnings 122 73 66 17 16 15 Net amount recognized in OCI Net actuarial loss 1 42 172 35 10 29 11 Net prior service cost/(credit) 2 – – – – (1) 6 Total amount recognized in OCI 42 172 35 10 28 17 Total amount recognized in Comprehensive income 164 245 101 27 44 32 1 Unamortized actuarial losses included in AOCI, before tax, were $388 million (2011 – $346 million) relating to the pension plans and $60 million (2011 – $51 million) relating to OPEB at December 31, 2012. 2 Unamortized prior service costs included in AOCI, before tax, were $4 million (2011 – $5 million) relating to OPEB at December 31, 2012. The Company estimates that approximately $24 million related to pension plans and $2 million related to OPEB at December 31, 2012 will be reclassified from AOCI into earnings in the next 12 months. Regulatory adjustments are recorded in the Consolidated Statements of Earnings, the Consolidated Statements of Comprehensive Income and the Consolidated Statements of Financial Position to reflect the difference between pension expense for accounting purposes and pension expense for ratemaking purposes. Offsetting regulatory assets or liabilities are recorded to the extent pension or OPEB costs or gains are expected to be collected from or refunded to customers in future rates (Note 5). The weighted average assumptions made in the measurement of the cost of the pension plans and OPEB are as follows: Pension OPEB Year ended December 31, 2012 2011 2010 2012 2011 2010 Discount rate 4.5% 5.6% 6.5% 4.4% 5.6% 6.3% Average rate of return on pension plan assets 7.1% 7.3% 7.3% 6.0% 6.0% 6.0% Average rate of salary increases 3.5% 3.5% 3.7% 148 < ENBRIDGE INC. 2012 FINANCIAL REPORT O O C S B D G RE F E C S NE E E Z I N T T I T N

Notes to the Consolidated Financial Statements > 149 MEDICAL COST TRENDS The assumed rates for the next year used to measure the expected cost of benefits are as follows: Medical Cost Trend Rate Assumption for Next Fiscal Year Ultimate Medical Cost Trend Rate Assumption Year in which Ultimate Medical Cost Trend Rate Assumption is Achieved Canadian Plans Drugs 8.6% 4.5% 2029 Other Medical 4.5% 4.5% – United States Plan 7.6% 4.5% 2030 A 1% increase in the assumed medical care trend rate would result in an increase of $36 million in the benefit obligation and an increase of $3 million in benefit and interest costs. A 1% decrease in the assumed medical care trend rate would result in a decrease of $29 million in the benefit obligation and a decrease of $2 million in benefit and interest costs. PLAN ASSETS The Company manages the investment risk of its pension funds by setting a long-term asset mix policy for each plan after consideration of: (i) the nature of pension plan liabilities; (ii) the investment horizon of the plan; (iii) the going concern and solvency funded status and cash flow requirements of the plan; (iv) the operating environment and financial situation of the Company and its ability to withstand fluctuations in pension contributions; and (v) the future economic and capital markets outlook with respect to investment returns, volatility of returns and correlation between assets. The overall expected rate of return is based on the asset allocation targets with estimates for returns on equity and debt securities based on long-term expectations. EXPECTED RATE OF RETURN ON PLAN ASSETS Pension OPEB Year ended December 31, 2012 2011 2012 2011 Canadian Plans 6.9% 7.0% United States Plan 7.3% 7.5% 6.0% 6.0% TARGET MIX FOR PLAN ASSETS Liquids Pipelines Plan Gas Distribution Plan United States Plan Equity securities 62.5% 53.5% 62.5% Fixed income securities 30.0% 40.0% 30.0% Other 7.5% 6.5% 7.5% MAJOR CATEGORIES OF PLAN ASSETS Plan assets are invested primarily in readily marketable investments with constraints on the credit quality of fixed income securities. As at December 31, 2012, the pension assets were invested 59.1% (2011 – 56.7%) in equity securities, 32.4% (2011 – 36.6%) in fixed income securities and 8.5% (2011 – 6.7%) in other. The OPEB assets were invested 58.1% (2011 – 55.3%) in equity securities, 35.5% (2011 – 40.3%) in fixed income securities and 6.4% (2011 – 4.4%) in other. D D S S A RE O C C N L T T I E M S P A A S S E L T N AS O O CT A RAT SET AN PL P N RN TU RET R F TE RA D ED TED TE PEC EXP XP R TS ATE A A LA SS EX TS O P R AR TA A A FO GET R OR A LA SS AS AN PL SET IX M T G O O O A P A MA

The following table summarizes the Company’s pension financial instruments at fair value. Non-financial instruments with a carrying value of $59 million (2011 – $77 million) have been excluded from the table below. 2012 2011 December 31, Level 1 1 Level 2 2 Level 3 3 Total Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) Pension Cash and cash equivalents 44 – – 44 14 – – 14 Fixed income securities Canadian government bonds 87 – – 87 115 – – 115 Corporate bonds and debentures – 4 – 4 – 4 – 4 Canadian corporate bond index fund 196 – – 196 158 – – 158 Canadian government bond index fund 152 – – 152 157 – – 157 United States debt index fund 45 2 – 47 62 – – 62 Equity Canadian equity securities 190 – – 190 148 – – 148 United States equity securities 24 – – 24 – – – – Global equity securities 9 – – 9 – – – – Canadian equity funds 64 39 – 103 21 74 – 95 United States equity funds 60 26 – 86 170 89 – 259 Global equity funds 255 159 – 414 191 7 – 198 Private equity investment 4 – – 61 61 – – 68 68 Real estate 5 – – 24 24 – – – – OPEB Cash and cash equivalents 4 – – 4 3 – – 3 Fixed income securities United States government and government agency bonds 22 – – 22 22 – – 22 Equity United States equity funds 17 19 – 36 15 14 – 29 1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2 assets include assets with significant observable inputs. 3 Level 3 assets include assets with significant unobservable inputs. 4 The fair value of the investment in United States Limited Partnership – Global Infrastructure Fund is established through the use of valuation models. 5 The fair value of the investment in Bentall Kennedy Prime Canadian Property Fund Ltd is established through the use of valuation models. Changes in the net fair value of plan assets classified as Level 3 in the fair value hierarchy were as follows: 2012 2011 (millions of Canadian dollars) Balance at beginning of year 68 65 Unrealized and realized gains 11 8 Purchases and settlements, net 6 (5) Balance at end of year 85 68 PLAN CONTRIBUTIONS BY THE COMPANY Pension OPEB Year ended December 31, 2012 2011 2012 2011 (millions of Canadian dollars) Total contributions 97 72 13 13 Contributions expected to be paid in 2013 140 13 150 < ENBRIDGE INC. 2012 FINANCIAL REPORT O O O P PA B R TR TH A S E A LA C C UT ANY NT PL Y M Y NS TIO TI RI AN

Notes to the Consolidated Financial Statements > 151 BENEFITS EXPECTED TO BE PAID BY THE COMPANY Year ended December 31, 2013 2014 2015 2016 2017 2018 – 2022 (millions of Canadian dollars) Expected future benefit payments 73 78 83 88 93 558 25. Other Income Year ended December 31, 2012 2011 2010 (millions of Canadian dollars) Net foreign currency gains 71 48 132 Allowance for equity funds used during construction 1 3 96 Interest income on affiliate loans 20 17 20 Interest income 7 3 17 Noverco preferred shares dividend income 42 30 15 OPEB recovery (Note 5) 89 – – Gain on acquisition (Note 6) – – 22 Other 10 16 16 240 117 318 26. Changes in Operating Assets and Liabilities Year ended December 31, 2012 2011 2010 (millions of Canadian dollars) Accounts receivable and other (122) 121 (878) Accounts receivable from affiliates 43 (17) 8 Inventory 42 93 (124) Deferred amounts and other assets (380) (320) (16) Accounts payable and other (319) 421 642 Accounts payable to affiliates (48) 41 (22) Interest payable 15 7 31 Other long-term liabilities 109 57 (65) (660) 403 (424) 27. Related Party Transactions All related party transactions are provided in the normal course of business and, unless otherwise noted, are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. Vector, a joint venture, contracts the services of Enbridge to operate the pipeline. Amounts for these services, which are charged at cost in accordance with service agreements were $6 million for the year ended December 31, 2012 (2011 – $6 million; 2010 – $7 million). Certain wholly-owned subsidiaries within the Gas Distribution and Gas Pipelines, Processing and Energy Services segments have transportation commitments with several joint venture affiliates that are accounted for using the equity method. Total amounts charged for transportation services were $127 million, $106 million and $102 million for the years ended December 31, 2012, 2011 and 2010, respectively. LONG-TERM NOTE RECEIVABLE FROM AFFILIATE Amounts receivable from affiliates include a series of loans to Vector totaling $178 million (2011 – $190 million), included in Deferred amounts and other assets, which require quarterly interest payments at annual interest rates from 5% to 8%. O O EF E PA P PA P P XP X B B B D D ED TS T A I F A C C EX E EN E Y N M E TH T Y I E T TE T E FI O h n ome e c r 5 I t . 2 O i C A i i i i in pe e s i b d e e n n h r n 6 a g g s s s a a a s t L l t t . 2 P R 2 i 7 n a e c Tr o e s s n r t a a d a . t t l y O B O AT R R R F F F O A A - C E L E E E L E I L I M V I E T N M T G N

28. Commitments and Contingencies COMMITMENTS The Company has signed contracts for the purchase of services, pipe and other materials, as well as transportation, totaling $4,668 million which are expected to be paid within the next five years and $1,023 million in total for years thereafter. Minimum future payments under operating leases are estimated at $329 million in aggregate. Estimated annual lease payments for the years ending December 31, 2013 through 2017 are $40 million, $41 million, $39 million, $38 million and $34 million, respectively, and $137 million thereafter. Total rental expense for operating leases, included in Operating and administrative expense, were $31 million, $28 million and $23 million for the years ended December 31, 2012, 2011 and 2010, respectively. ENBRIDGE ENERGY PARTNERS, L.P. Enbridge holds an approximate 21.8% combined direct and indirect ownership interest in EEP, which is consolidated with noncontrolling interests within the Sponsored Investments segment. ENVIRONMENTAL LIABILITIES As at December 31, 2012, the Company had $107 million (2011 – $175 million) included in current liabilities and $18 million (2011 – $32 million) included in Other long-term liabilities, which have been accrued for costs incurred primarily to address remediation of contaminated sites, asbestos containing materials, management of hazardous waste material disposal, outstanding air quality measures for certain of EEP’s liquids and natural gas assets and penalties that have been or are expected to be assessed. LAKEHEAD SYSTEM LINE 14 CRUDE OIL RELEASE On July 27, 2012, a release of crude oil was detected on Line 14 of EEP’s Lakehead System near Grand Marsh, Wisconsin. The estimated volume of oil released was approximately 1,700 barrels. EEP received a Corrective Action Order (CAO) from the Pipeline and Hazardous Materials Safety Administration (PHMSA) on July 30, 2012, followed by an amended CAO on August 1, 2012. The CAOs required EEP to take certain corrective actions, some of which have already been completed and some are still ongoing, as part of an overall plan for its Lakehead System. A notable part of the CAOs was to hire an independent third party pipeline expert to review and assess EEP’s overall integrity program. An independent third party expert was contracted during the third quarter of 2012 and its work is currently ongoing. Upon restart of Line 14 on August 7, 2012, PHMSA restricted the operating pressure to 80% of the pressure in place at the time immediately prior to the incident. The pressure restrictions will remain in place until such time EEP can demonstrate that the root cause of the incident has been remediated. EEP has revised the disclosed estimate for repair and remediation related costs associated with this crude oil release as at December 31, 2012 to approximately US$10 million ($1 million after-tax attributable to Enbridge), inclusive of approximately US$2 million of lost revenue, and excluding any fines and penalties. Despite the efforts EEP has made to ensure the reasonableness of its estimate, changes to the estimated amounts associated with this release are possible as more reliable information becomes available. EEP will be pursuing claims under Enbridge’s comprehensive insurance policy, although it does not expect any recoveries to be significant. 152 < ENBRIDGE INC. 2012 FINANCIAL REPORT C 8 i i i n n n n mm s s d e n c g o e e m t t t a o C . 2 O S T T M E C N M I M S D B P P R R R R GY A . . L E N T E N E E G I N E , O ES B AB R A TA A IA ENVI TI LIT L BI LIA L AL ENT EN M ON VI ENV SYST O A EA D D AD AS R CR R E A EA A LA 4 C U L KEH L SE LEA EL REL I E 1 N LI L EM TEM TE YS EH AKE

Notes to the Consolidated Financial Statements > 153 LAKEHEAD SYSTEM LINES AND 6B CRUDE OIL RELEASES LINE 6B CRUDE OIL RELEASE On July 26, 2010, a release of crude oil on Line 6B of EEP’s Lakehead System was reported near Marshall, Michigan. EEP estimates that approximately 20,000 barrels of crude oil were leaked at the site, a portion of which reached the Talmadge Creek, a waterway that feeds the Kalamazoo River. The released crude oil affected approximately 61 kilometres (38 miles) of shoreline along the Talmadge Creek and Kalamazoo River waterways, including residential areas, businesses, farmland and marshland between Marshall and downstream of Battle Creek, Michigan. In response to the release, a unified command structure was established under the jurisdiction of the Environmental Protection Agency (EPA), the Michigan Department of Natural Resources and Environment and other federal, state and local agencies. During the second quarter of 2012, local authorities allowed the Kalamazoo River and Morrow Lake, which were affected by the Line 6B crude oil release, to be re-opened for recreational use. EEP continues to perform necessary remediation, restoration and monitoring of the areas affected by the Line 6B crude oil release. EEP expects to make payments for additional costs associated with submerged oil and sheen monitoring and recovery operations, including reassessment, remediation and restoration of the area, air and groundwater monitoring, scientific studies and hydrodynamic modeling, along with legal, professional and regulatory costs through future periods. All of the initiatives EEP is undertaking in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities. On July 2, 2012, EEP received a Notice of Probable Violation (NOPV) from the PHMSA related to the July 26, 2010 Line 6B crude oil release, which resulted in payment of a US$3.7 million civil penalty in the third quarter of 2012. EEP included the amount of the penalty in its total estimated cost for the Line 6B crude oil release. In addition, on July 10, 2012 the National Transportation Safety Board presented the results of its investigation into the Line 6B crude oil release and subsequently publicly posted its final report on July 26, 2012. As at December 31, 2012, EEP revised the total incident cost accrual to US$820 million ($137 million after-tax attributable to Enbridge), primarily due to an estimate of extended oversight by regulators and additional legal costs associated with various lawsuits, which is an increase of US$55 million ($8 million after-tax attributable to Enbridge) from its estimate at December 31, 2011. This total estimate is before insurance recoveries and excludes additional fines and penalties, which may be imposed by federal, state and local government agencies, other than the PHMSA civil penalty described above. On October 3, 2012, EEP received a letter from the EPA regarding a Proposed Order for potential incremental containment and active recovery of submerged oil. EEP is in discussions with the EPA regarding the agency’s intent with respect to certain elements of the Proposed Order and the appropriate scope of these activities. The nature and scope of any additional remediation activities that regulators may require is currently uncertain. Studies and additional technical evaluation by EEP, the EPA and other regulatory agencies may need to be completed before a final determination of any additional remediation activities can be determined. EEP has accrued the estimated costs it deemed likely to be incurred. However, when a final determination of the appropriate nature and scope of any additional remediation is made, it could result in significant cost being accrued. Expected losses associated with the Line 6B crude oil release included those costs that were considered probable and that could be reasonably estimated at December 31, 2012. Despite the efforts EEP has made to ensure the reasonableness of its estimates, there continues to be the potential for EEP to incur additional costs in connection with this crude oil release due to variations in any or all of the cost categories, including modified or revised requirements from regulatory agencies, in addition to fines and penalties and expenditures associated with litigation and settlement of claims. S ES O A EA E D B D D S 6 6 R R ES E A A 6A A EA E A C KE K U S YS Y L H E

LINE 6A CRUDE OIL RELEASE A release of crude oil from Line 6A of EEP’s Lakehead System was reported in an industrial area of Romeoville, Illinois on September 9, 2010. EEP estimates that approximately 9,000 barrels of crude oil were released, of which approximately 1,400 barrels were removed from the pipeline as part of the repair. Some of the released crude oil went onto a roadway, into a storm sewer, a waste water treatment facility and then into a nearby retention pond. All but a small amount of the crude oil was recovered. EEP completed excavation and replacement of the pipeline segment and returned it to service on September 17, 2010. The cause of the crude oil release remains subject to investigation by federal and state environmental and pipeline safety regulators. EEP continues to monitor the areas affected by the crude oil release from Line 6A of its Lakehead System near Romeoville, Illinois in September 2010 for any additional requirements; however, the cleanup, remediation and restoration of the areas affected by the release have been completed. In connection with this crude oil release, the cost estimate as at December 31, 2012 remains at approximately US$48 million ($7 million after-tax attributable to Enbridge), before insurance recoveries and excluding fines and penalties. EEP has the potential of incurring additional costs in connection with this crude oil release, including fines and penalties as well as expenditures associated with litigation. EEP is pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained. INSURANCE RECOVERIES EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates which renews in May of each year. In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis based on an insurance allocation agreement EEP has entered into with Enbridge and one of Enbridge’s subsidiaries. The insurance program includes commercial liability insurance coverage that is consistent with coverage considered customary for its industry and includes coverage for environmental incidents such as those incurred for the crude oil releases from Lines 6A and 6B, excluding costs for fines and penalties. The claims for the crude oil release for Line 6B are covered by Enbridge’s comprehensive insurance policy that expired on April 30, 2011, which had an aggregate limit of US$650 million for pollution liability. Based on EEP’s remediation spending through December 31, 2012, Enbridge and its affiliates have exceeded the limits of their coverage under this insurance policy. Additionally, fines and penalties would not be covered under the existing insurance policy. For the years ended December 31, 2012 and 2011, EEP recognized US$170 million ($24 million after-tax attributable to Enbridge) and US$335 million ($50 million after-tax attributable to Enbridge), respectively, of insurance recoveries as reductions to Environmental costs in the Consolidated Statements of Earnings. As at December 31, 2012, EEP had recorded total insurance recoveries of US$505 million ($74 million after-tax attributable to Enbridge) for the Line 6B crude oil release and expects to recover the balance of the aggregate liability insurance coverage of US$145 from its insurers in future periods. EEP will record receivables for additional amounts received through insurance recoveries during the period it deems recovery to be probable. Effective May 1, 2012, Enbridge renewed its comprehensive insurance program, through April 30, 2013, with a current liability aggregate limit of US$660 million, including sudden and accidental pollution liability. 154 < ENBRIDGE INC. 2012 FINANCIAL REPORT

Notes to the Consolidated Financial Statements > 155 LEGAL AND REGULATORY PROCEEDINGS A number of United States governmental agencies and regulators have initiated investigations into the Line 6A and Line 6B crude oil releases. Approximately 30 actions or claims have been filed against Enbridge, EEP or their affiliates in United States federal and state courts in connection with the Line 6B crude oil release, including direct actions and actions seeking class status. Based on the current status of these cases, EEP does not expect the outcome of these actions to be material. As noted above, on July 2, 2012, PHMSA announced a NOPV related to the Line 6B crude oil release, including a civil penalty of US$3.7 million that EEP paid in the third quarter of 2012. One claim related to the Line 6A crude oil release has been filed against Enbridge, EEP or their affiliates by the State of Illinois in the Illinois state court. The parties are currently operating under an agreed interim order. TAX MATTERS Enbridge and its subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in the Company’s view, these tax positions, if challenged by tax authorities, may not be fully sustained on review. OTHER LEGAL AND REGULATORY PROCEEDINGS The Company and its subsidiaries are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. While the final outcome of such actions and proceedings cannot be predicted with certainty, Management believes that the resolution of such actions and proceedings will not have a material impact on the Company’s consolidated financial position or results of operations. 29. Guarantees The Company has agreed to indemnify EEP from and against substantially all liabilities, including liabilities relating to environmental matters, arising from operations prior to the transfer of its pipeline operations to EEP in 1991. This indemnification does not apply to amounts that EEP would be able to recover in its tariff rates if not recovered through insurance or to any liabilities relating to a change in laws after December 27, 1991. The Company has also agreed to indemnify EEM for any tax liability related to EEM’s formation, management of EEP and ownership of i-units of EEP. The Company has not made any significant payment under these tax indemnifications. The Company does not believe there is a material exposure at this time. In the normal course of conducting business, the Company enters into agreements which indemnify third parties. Examples include indemnifying counterparties pursuant to sale agreements for assets or businesses in matters such as breaches of representations; warranties or covenants; loss or damages to property; environmental liabilities; changes in laws; valuation differences; litigation; and contingent liabilities. The Company may indemnify the purchaser for certain tax liabilities incurred while the Company owned the assets or for a misrepresentation related to taxes that result in a loss to the purchaser. Similarly, the Company may indemnify the purchaser of assets for certain tax liabilities related to those assets. The Company may also indemnify for breaches of representations; warranties or covenants; changes in laws; intellectual property rights infringement; and litigations. The Company cannot reasonably estimate the maximum potential amounts that could become payable to third parties under these agreements; however, historically, the Company has not made any significant payments under these indemnification provisions. While these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are circumstances where the amount and duration are unlimited. The above-noted indemnifications and guarantees have not had, and are not reasonably likely to have, a material effect on the Company’s financial condition, changes in financial condition, earnings, liquidity, capital expenditures or capital resources. TA R X AT A S E T M O O G T P R D D GS A A R R R E O Y AT C U N L E L L E I E G N E H 29 n e e ra s a . t u G

FIVE-YEAR CONSOLIDATED HIGHLIGHTS 2012 1 2011 1 2010 1 2009 2 2008 2 (millions of Canadian dollars; per share amounts in Canadian dollars) Earnings attributable to common shareholders Liquids Pipelines 726 505 531 445 328 Gas Distribution 207 (88) 150 186 161 Gas Pipelines, Processing and Energy Services (478) 305 125 428 767 Sponsored Investments 282 269 98 141 111 Corporate (127) (171) 40 355 (46) 610 820 944 1,555 1,321 Earnings per common share 3 0.79 1.09 1.27 2.13 1.84 Diluted earnings per common share 3 0.78 1.08 1.26 2.12 1.82 Adjusted earnings Liquids Pipelines 684 536 511 454 332 Gas Distribution 176 173 162 154 141 Gas Pipelines, Processing and Energy Services 154 163 123 116 141 Sponsored Investments 263 244 206 151 101 Corporate (28) (16) (25) (20) (38) 1,249 1,100 977 855 677 Adjusted earnings per common share 3,4 1.62 1.46 1.32 1.17 0.94 Cash flow data Cash provided by operating activities 2,874 3,371 1,877 2,017 1,372 Cash used in investing activities (6,204) (5,079) (3,902) (3,306) (2,853) Cash provided by financing activities 4,395 2,030 1,957 1,082 1,840 Dividends Common share dividends declared 895 759 648 555 489 Dividends paid per common share 3 1.13 0.98 0.85 0.74 0.66 Shares outstanding (millions) Weighted average common shares outstanding 3 772 751 741 728 720 Diluted weighted average common shares outstanding 3 785 761 748 733 725 1 Financial information has been extracted from financial statements prepared in accordance with U.S. GAAP. 2 Financial information has been extracted from financial statements prepared in accordance with Canadian GAAP. 3 Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011. 4 Adjusted earnings represent earnings attributable to common shareholders adjusted for non-recurring or non-operating factors. Adjusted earnings and adjusted earnings per common share are non-GAAP measures that do not have any standardized meaning prescribed by generally accepted accounting principles. For more information on non-GAAP measures see page 9. 156 < ENBRIDGE INC. 2012 FINANCIAL REPORT O O F D D S H R -Y AT A C G S E G T H H E N E V I L I I L I

Five-Year Consolidated Highlights > 157 FIVE-YEAR CONSOLIDATED HIGHLIGHTS 2012 1 2011 1 2010 1 2009 2 2008 2 (per share amounts in Canadian dollars) Common share trading (TSX) 3 High 43.05 38.17 29.13 24.46 21.64 Low 35.39 27.05 23.02 17.60 16.55 Close 43.02 38.09 28.14 24.32 19.78 Volume (millions) 365 396 461 457 585 Financial ratios Return on average equity 4 6.3% 11.3% 14.1% 22.2% 22.2% Return on average capital employed 5 3.5% 4.5% 5.0% 8.9% 9.9% Debt to debt plus equity 6 67.1% 72.9% 73.7% 66.2% 66.6% Dividend payout ratio 7 69.8% 67.1% 64.4% 63.0% 70.2% Operating data Liquids Pipelines – Average deliveries (thousands of barrels per day) Canadian Mainline 8 1,646 1,554 1,537 1,562 1,522 Regional Oil Sands System 9 414 334 291 259 202 Spearhead Pipeline 151 82 144 121 110 Gas Distribution – Enbridge Gas Distribution (EGD) Volumes (billions of cubic feet) 395 426 409 408 433 Number of active customers (thousands) 10 2,032 1,997 1,963 1,937 1,898 Heating degree days 11 Actual 3,194 3,597 3,466 3,767 3,802 Forecast based on normal weather 3,532 3,602 3,546 3,514 3,543 Gas Pipelines, Processing and Energy Services – Average throughput volume (millions of cublic feet per day) Alliance Pipeline US 1,553 1,564 1,600 1,601 1,609 Vector Pipeline 1,534 1,525 1,456 1,334 1,321 Enbridge Offshore Pipelines 1,540 1,595 1,962 2,037 1,672 1 Financial ratios have been calculated using information from financial statements prepared in accordance with U.S. GAAP. 2 Financial ratios have been calculated using information from financial statements prepared in accordance with Canadian GAAP. 3 Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011. 4 Earnings applicable to common shareholders divided by average equity. 5 Sum of after-tax earnings and after-tax interest expense, divided by weighted average capital employed. Capital employed is equal to the sum of equity, Enbridge Gas Distribution preferred shares, deferred income taxes, deferred credits and total debt (including short-term borrowings). 6 Total debt (including short-term borrowings) divided by the sum of total debt and equity. 7 Dividends per common share divided by adjusted earnings per common share. 8 Canadian Mainline includes deliveries ex-Gretna, Manitoba, which is made up of United States and eastern Canada deliveries originating from western Canada. 9 Volumes are for the Athabasca mainline and the Waupisoo Pipeline and exclude laterals on the Regional Oil Sands System. 10 Number of active customers is the number of natural gas consuming EGD customers at the end of the period. 11 Heating degree days is a measure of coldness which is indicative of volumetric requirements for natural gas utilized for heating purposes in EGD’s franchise area. It is calculated by accumulating, for the fiscal period, the total number of degrees each day by which the daily mean temperature falls below 18 degrees Celsius. The figures given are those accumulated in the Greater Toronto Area. O O F D D S S H R -Y AT A C G E G T H H E N E V I L I I L I

GLOSSARY AFUDC allowance for funds used during construction Alliance Alliance System Amherstburg Amherstburg Solar Project AOCI accumulated other comprehensive income/(loss) ASU Accounting Standards Update bcf/d billion cubic feet per day bpd barrels per day CLT Canadian Local Toll CSR corporate social responsibility CTS Competitive Toll Settlement EECI Enbridge Energy Company, Inc. EEDI Enbridge Energy Distribution Inc. EELP Enbridge Energy, Limited Partnership EEM Enbridge Energy Management, L.L.C. EEP Enbridge Energy Partners, L.P. EGD Enbridge Gas Distribution Inc. EGNB Enbridge Gas New Brunswick Inc. Enbridge Enbridge Inc. ENF Enbridge Income Fund Holdings Inc. EPI Enbridge Pipelines Inc. EUB New Brunswick Energy and Utilities Board FERC Federal Energy Regulatory Commission Greenwich Greenwich Wind Energy Project IJT International Joint Tariff IR incentive regulation ISO incentive stock options ITS incentive tolling settlement JRP Joint Review Panel MD&A Management’s Discussion and Analysis mmcf/d million cubic feet per day MW megawatts MWH megawatt hours NEB National Energy Board NGL natural gas liquids Northern Gateway proposed Northern Gateway Project OCI other comprehensive income/(loss) OEB Ontario Energy Board Offshore Enbridge Offshore Pipelines OPEB other postretirement benefits ORM Plan Operational Risk Management Plan PBSO performance based stock options PPA power purchase agreement PRA Peace River Arch PSU performance stock units ROE return on equity RSU restricted stock units Seaway Pipeline Seaway Crude Pipeline System SEC Securities and Exchange Commission Silver State Silver State North Solar Project TEP Texas Express Pipeline the Company Enbridge Inc. the Fund Enbridge Income Fund Tilbury Tilbury Solar Project U.S. GAAP accounting principles generally accepted in the United States of America Vector Vector Pipeline WCSB Western Canadian Sedimentary Basin WRGGS Walker Ridge Gas Gathering System 158 < ENBRIDGE INC. 2012 FINANCIAL REPORT O RY A S S L G

Designed and produced by Karo Group. Printed in British Columbia, Canada by Blanchette Press. INVESTOR INFORMATION COMMON AND PREFERENCE SHARES The Common Shares of Enbridge Inc. trade in Canada on the Toronto Stock Exchange and in the United States on the New York Stock Exchange under the trading symbol ‘‘ENB’’. The Preference Shares of Enbridge Inc. trade in Canada on the Toronto Stock Exchange under the following trading symbols: Series A – ENB.PR.A Series B – ENB.PR.B Series D – ENB.PR.D Series F – ENB.PR.F Series H – ENB.PR.H Series J – ENB.PR.U Series L – ENB.PF.U Series N – ENB.PR.N Series P – ENB.PR.P Series R – ENB.PR.T REGISTRAR AND TRANSFER AGENT IN CANADA For information relating to shareholdings, shareholder investment plan, dividends, direct dividend deposit, dividend re-investment accounts and lost certificates please contact: CIBC Mellon Trust Company 1 P.O. Box 700 Station B Montreal, Québec H3B 3K3 Toll free: 800.387.0825 Internet: www.canstockta.com/investorinquiry CIBC Mellon Trust Company also has offices in Halifax, Montreal, Calgary and Vancouver. 1 Canadian Stock Transfer Company Inc. acts as the Administrative Agent for CIBC Mellon Trust Company CO-REGISTRAR AND CO-TRANSFER AGENT IN THE UNITED STATES Computershare 480 Washington Blvd. Jersey City, New Jersey U.S.A. 07310 AUDITORS PricewaterhouseCoopers LLP DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN Enbridge Inc. offers a Dividend Reinvestment and Share Purchase Plan that enables shareholders to reinvest their cash dividends in Common Shares and to make additional cash payments for purchases at the market price. Effective with dividends payable on March 1, 2008, participants in the Plan will receive a two per cent discount on the purchase of common shares with reinvested dividends. Details may be obtained from the Investor Information section of the Enbridge website at or by contacting CIBC Mellon Trust Company at any of the locations listed above. NEW YORK STOCK EXCHANGE DISCLOSURE DIFFERENCES As a foreign private issuer, Enbridge Inc. is required to disclose any significant ways in which its corporate governance practices differ from those followed by United States companies under NYSE listing standards. This disclosure can be obtained from the U.S. Compliance subsection of the Corporate Governance section of the Enbridge website at enbridge.com. FORM 40-F The Company files annually with the United States Securities and Exchange Commission a report known as the Annual Report on Form 40-F. Copies of the Form 40-F are available, free of charge, upon written request to the Corporate Secretary of the Company. In addition a link to it is available on the ‘‘Reports and Filings’’ subsection of the ‘‘Financial Reports’’ section of our website. CORPORATE SOCIAL RESPONSIBILITY REPORT Enbridge publishes an annual Corporate Social Responsibility report. The report is available on the Company’s website at csr.enbridge.com. REGISTERED OFFICE Enbridge Inc. 3000, 425 – 1st Street S.W. Calgary, Alberta, Canada T2P 3L8 Telephone: 403.231.3900 Facsimile: 403.231.3920 Internet: enbridge.com Enbridge is committed to reducing its impact on the environment in every way, including the production of this publication. This report was printed entirely on FSC® Certified paper containing 100% post-consumer recycled fibre and is manufactured using biogas and wind energy. Investor Information > 159

Enbridge Inc., a Canadian company, is a North American leader in delivering energy and one of the Global 100 Most Sustainable Corporations in the World. As a transporter of energy, Enbridge operates, in Canada and the U.S., the world’s longest crude oil and liquids transportation system. The Company also has a significant and growing involvement in natural gas gathering, transmission and midstream businesses, and an increasing involvement in power transmission. As a distributor of energy, Enbridge owns and operates Canada’s largest natural gas distribution company, and provides distribution services in Ontario, Quebec, New Brunswick and New York State. As a generator of energy, Enbridge has interests in close to 1,300 megawatts of renewable and alternative energy generating capacity and is expanding its interests in wind and solar energy, geothermal and hybrid fuel cells. Enbridge employs approximately 10,000 people, primarily in Canada and the U.S. and is ranked as one of Canada’s Greenest Employers and one of the Top 100 Companies to Work for in Canada. Enbridge’s common shares trade on the Toronto and New York stock exchanges under the symbol ENB. For more information, visit enbridge.com

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